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

                                   FORM 10-KSB

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

                   For the fiscal year ended December 31, 2002

          [ ]  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)

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

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

                 Title of each class                       Name of each exchange
                                                           on which registered
                 -------------------                       ---------------------

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

                COMMON STOCK, $0.001 PAR VALUE, CLASS A WARRANTS
--------------------------------------------------------------------------------
                                (Title of class)

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. [X]

The issuer's revenue for the year ended December 31, 2002 was $5,988,342.

The aggregate market value of the voting and non-voting common equity (excluding
warrants) held by non-affiliates on April 7, 2003 was $3,898,010. This amount
was computed using closing price of the issuer's common stock on April 7, 2003
on the NASDAQ National Market.

As of April 7, 2003, the issuer had outstanding a total of 6,550,000 shares of
its $0.001 par value Common Stock.

Documents incorporated by reference - Proxy Statement for 2003 Annual Meeting is
incorporated by reference in response to Items 9, 10, 11 and 12 of Part III.

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

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                               GMX RESOURCES INC.
                                   FORM 10-KSB
                                TABLE OF CONTENTS
                                                                           PAGE
                                                                           ----


                                     PART I


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

           General...........................................................1
           2001 Equity Offerings.............................................1
           Drilling Contract.................................................2
           2002 Developments.................................................2
           Current Conditions................................................2
           Business Strategy.................................................3
           Marketing.........................................................4
           Regulation........................................................5
           Gas Gathering.....................................................7
           Competition.......................................................7
           Facilities........................................................8
           Employees.........................................................8
           Certain Technical Terms...........................................8

Item 2.    PROPERTIES.......................................................12

           Reserves.........................................................14
           Costs Incurred and Acquisition and Drilling Results..............16
           Productive Well Summary..........................................17

Item 3.    LEGAL PROCEEDINGS................................................17

Item 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..............18


                                     PART II


Item 5.    MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
           STOCKHOLDER MATTERS..............................................18

Item 6.    MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF
           OPERATION........................................................20

           Selected Financial Data..........................................20
           Summary Operating and Reserve Data...............................21
           Critical Accounting Policies.....................................22
           Results of Operations for the Year Ended December 31, 2002
             Compared to Year Ended December 31, 2001.......................23

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           Results of Operations--Year Ended December 31, 2001
             Compared to Year Ended December 31, 2000.......................24
           Capital Resources and Liquidity..................................26
           Cash Flow--2001 Compared to 2000.................................26
           Credit Facility..................................................27
           Working Capital..................................................28
           Commitments and Capital Expenditures.............................28
           Liquidity and Financing Considerations...........................29
           Price Risk Management............................................29
           Impact of Recently Issued Accounting Standards Not Yet Adopted...30
           Forward-Looking Statements.......................................31
           Risk Factors Related to GMX......................................32
           Risks Related to the Oil and Gas Industry........................34

Item 7.    FINANCIAL STATEMENTS.............................................39

Item 8.    CHANGES  IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
           ACCOUNTING AND FINANCIAL DISCLOSURE..............................39


                             PART III


Item 9.    DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL
           PERSONS; COMPLIANCE WITH SECTION 16(a) OF THE
           EXCHANGE ACT.....................................................39

Item 10.   EXECUTIVE COMPENSATION...........................................39

Item 11.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERSHIP
           AND MANAGEMENT...................................................40

Item 12.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS...................40

Item 13.   EXHIBITS AND REPORTS ON FORM 8-K.................................40

Item 14.   CONTROLS AND PROCEDURES..........................................41

SIGNATURES..................................................................42

CERTIFICATIONS..............................................................43

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                                     PART I

ITEM 1. BUSINESS

GENERAL

     GMX Resources Inc. (referred to herein as "GMX" or the "Company") is an
independent oil and gas company headquartered in Oklahoma City, Oklahoma. 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 believe 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.

     Since the acquisition, through December 31, 2002, we have conducted an
extensive geological and engineering evaluation of the property base, improved
the operating efficiencies of the properties, recompleted or reworked 61 wells,
drilled 13 additional wells and acquired additional related acreage and
reserves. As a result, we have added proved reserves in existing producing wells
and identified proved reserves that can be developed by drilling additional
wells.

2001 EQUITY OFFERINGS

     On February 12, 2001, we completed an initial public offering of 1,250,000
units at $8.00 per unit underwritten by Paulson Investment Company, Inc. and
I-Bankers Securities Incorporated. 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 units traded as units until
March 15, 2001 when the common stock, Class A warrants and Class B warrants
became separately tradeable on the NASDAQ SmallCap Market. The net proceeds of
the offering amounting to approximately $8.5 million have been used primarily
for development drilling.

     On June 22, 2001, our common stock became eligible for trading on the
NASDAQ National Market. 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.
This firm commitment offering was also underwritten by Paulson Investment
Company, Inc., and I-Bankers Securities Incorporated. The proceeds of the
offering, net of underwriters' fees and other expenses, were approximately $11.3
million, and have been used primarily for the development drilling of oil and
gas wells.

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DRILLING CONTRACT

     On May 29, 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. The day rate was payable regardless of whether we were actually using the
rigs. Our payment obligations were secured by standby letters of credit in the
aggregate amount of $1,000,000, $500,000 per rig, issued by our lender under our
credit facility in favor of Nabors.

     On December 13, 2001, we terminated the contracts 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.
On December 20, 2002, we received a jury verdict in our favor in our lawsuit
against Nabors in the United States District Court for the Western District of
Oklahoma after a five day trial. As a result of the jury verdict, the Company
has no liability to Nabors on its claim for approximately $10 million in
contract termination damages. In March 2003, Nabors filed a notice of appeal of
the jury verdict. The appeal process is likely to take more than 12 months and
if Nabors is successful will likely result in a new trial. See "Legal
Proceedings."

2002 DEVELOPMENTS

     Primarily due to uncertainties associated with the Nabors litigation as
well as technical defaults under our credit facility, the independent auditors'
opinion on our year end 2001 financial statement contained a "going concern"
explanatory paragraph. Due to liquidity issues we curtailed all drilling and
development activities in 2002 and implemented a number of actions to reduce
overhead costs.

     On July 17, 2002, we engaged Petroleum Place Advisors to assist us as a
financial advisor in connection with the possible property sales and other
alternatives. Effective as of September 30, 2002, we completed the sale of oil
and gas properties in Kansas. This sale resulted in divestiture of all of our
Kansas properties which had proved reserves of 9,571 MMcfe as of December 31,
2001. Net proceeds of the sales were $3.6 million of which $3.3 million was
applied to our bank debt.

     We also solicited bids through Petroleum Place for either a purchase of our
East Texas properties or a joint venture to develop these properties. This
process concluded in December 2002. After our success in the trial court in the
Nabors litigation, we elected to continue to evaluate other strategic
alternatives rather than accept proposals made at that time.

CURRENT CONDITIONS

     As of December 31, 2002 and April 10, 2003, we were currently in default
under our bank credit facility because of our $10.1 million working capital
deficit, of which $8.1 million is

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bank debt that is due on May 1, 2003. We have substantially reduced overhead and
believe current cash flow is sufficient to meet our current obligations, but is
not sufficient to fund any drilling or to fully repay bank debt. We are actively
exploring refinancing with other lenders and possible joint venture drilling
arrangements to provide funding for drilling activities. However, there is no
assurance that we will be successful and if our lending bank pursues enforcement
action to collect its loan, we do not have sufficient liquid resources to pay
the amount due. See "Management's Discussion and Analysis or Plan of Operation."

BUSINESS STRATEGY

     If we are able to obtain financing, our strategy will be 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 28 years. He was formerly Chairman and Chief Executive
Officer of OEXCO, Inc., 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 which manufactured and sold road building equipment.

     SUBSTANTIAL DRILLING AND EXPLOITATION OPPORTUNITIES. We have a substantial
inventory of drilling and recompletion projects with an estimated 47 Bcfe of
proved undeveloped reserves as of December 31, 2002. These projects include 26
recompletion projects and 63 new drilling locations with proved undeveloped
reserves. We expect to locate additional proved drilling and recompletion
opportunities as our evaluation and drilling of the property base continues.
Based on our December 31, 2002 reserve report, the pre-tax present value of the
proved reserves is $81 million with anticipated future development costs of
$39.5 million.

     SIGNIFICANT INVENTORY OF UNPROVED PROSPECTS. We have approximately 200
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 can be held and drilled in order of priority without concern about lease
expiration.

     EMPHASIS ON GAS RESERVES. Production for 2002 was 80% gas and 20% oil.
Proved reserves as of December 31, 2002 are 85% gas and 15% 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.

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     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. During the past several years, regional surpluses and
shortages of natural gas have occurred, resulting in wide fluctuations in prices
received.

     Substantially all of our gas from our East Texas 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.

     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 generally an established or
"posted" price that is offered to all producers. During the last several years
prices paid for crude oil have fluctuated substantially. Future oil prices are
difficult to predict due to the impact of worldwide economic trends, coupled
with supply and demand variables, and such non-economic factors as the impact of
political considerations on OPEC (Organization of the Petroleum Exporting
Countries) pricing policies and the possibility of supply interruptions.

     Our largest purchasers include Teppco Crude and Crosstex Pipeline Company,
which accounts for 95 % and 86% of oil and natural gas sales currently. We do
not believe that the loss of any of our purchasers would have a material adverse
affect on our operations. None of our gas or oil sales contracts have a term of
more than one year.

                                        4
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REGULATION

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

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

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

     A variety of federal and state laws and regulations govern the
environmental aspects of natural gas and oil production, transportation and
processing and may, in addition to other laws, impose liability in the event of
discharges, whether or not accidental, failure to notify the proper authorities
of a discharge, and other noncompliance with those laws. Compliance with such
laws and regulations may increase the cost of oil and gas exploration,
development and production, although we do not currently 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.

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Persons who are or were responsible for releases of hazardous substances under
CERCLA may be subject to joint and severable liability for the costs of cleaning
up the hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for neighboring landowners
and other third parties to file claims for personal injury and property damage
allegedly caused by the hazardous substances released into the environment. We
could be subject to the liability under CERCLA because our drilling and
production activities generate relatively small amounts of liquid and solid
waste that may be subject to classification as hazardous substances under
CERCLA.

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

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

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

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

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     MARKETING AND TRANSPORTATION. The interstate transportation and sale for
resale of natural gas is regulated by the Federal Energy Regulatory Commission
("FERC") under the Natural Gas Act of 1938. The sale and transportation of
natural gas also is subject to regulation by various state agencies. The Natural
Gas Wellhead Decontrol Act of 1989 eliminated all gas price regulation effective
January 1, 1993. In addition, FERC recently has proposed several rules and
orders concerning transportation and marketing of natural gas. We cannot predict
the impact of these rules and other regulatory developments on the Company or
our operations.

     In 1992, FERC finalized Order 636, and also has promulgated regulations
pertaining to the restructuring of the interstate transportation of natural gas.
Pipelines serving this function have since been required to "unbundle" the
various components of their service offerings, which include gathering,
transportation, storage, and balancing services. In their current capacity,
pipeline companies must provide their customers with only the specific service
desired, on a non-discriminatory basis. Although we are not an interstate
pipeline, we believe the changes brought about by Order 636 have increased
competition in the marketplace, resulting in greater market volatility.

     Various rules, regulations and orders, as well as statutory provisions may
affect the price of natural gas production and the transportation and marketing
of natural gas.

GAS GATHERING

     We have acquired, constructed and own, through a wholly-owned subsidiary,
Endeavor, gas gathering lines and compression equipment for gathering and
delivering of natural gas from our east Texas properties. As of December 31,
2002, this gathering system consisted of approximately 34 miles of gathering
lines that collect gas from approximately 40 wells, which accounted for
approximately 95% and 89% of our gas production from this area in 2002 and 2001,
respectively. 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."

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

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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 the regions in which we
own properties has resulted in increased demand for drilling rigs and other
oilfield equipment and services. We may 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, 2002, we leased approximately 6,749 square feet in
Oklahoma City, Oklahoma for our corporate headquarters. The annual rental cost
is approximately $94,485.

EMPLOYEES

     As of December 31, 2002, we had 11 full-time employees of which three are
management and the balance are clerical or technical employees. This is down
from 18 full-time employees at December 31, 2001. We also use 5 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.

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.

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

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

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

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

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

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

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

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

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

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

     MBBLS. Thousand barrels.

     MBTU. Thousand Btus.

     MCF. Thousand cubic feet.

     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.

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<PAGE>

     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 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. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not escalations
based upon future conditions.

     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

                                       10
<PAGE>

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.

     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.



                                       11
<PAGE>

ITEM 2. PROPERTIES

     As of December 31, 2002, we owned properties in the following productive
basins in the United States:

          o    The Sabine Uplift in East Texas and Louisiana;

          o    The Tatum Basin in Southeast New Mexico.

     The following table sets forth certain information regarding our activities
in each of these areas as of December 31, 2002.

                                             EAST TEXAS     SOUTHEAST
                                                 AND           NEW
                                              LOUISIANA       MEXICO      TOTAL
                                              ---------       ------      -----
     PROPERTY STATISTICS:
     --------------------
     Proved reserves (MMcfe)                    65,293        1,370       66,663
     Percent of total proved reserves              98%           2%         100%
     Gross producing wells                          50            7           57
     Net producing wells                          37.6          5.6         43.2
     Gross acreage                              20,304        2,077       22,381
     Net acreage                                17,917        1,821       19,738
     Proved undeveloped reserves (MMcfe)        45,749          790       46,539
     Estimated development costs ($000s)       $39,268         $250      $39,518
     Proved undeveloped locations                   65            1           66

     YEAR ENDED DECEMBER 31, 2002 RESULTS:
     Production (net MMcfe) 1                    1,881           81        1,962
     Average net daily production (Mcfe)         5,153          222        5,375

          -----------------------
          1    Does not include 2002 production from our Kansas properties that
               were sold in September, 2002.

     Additional information related to our oil and gas activities is included in
Notes J and K to the financial statements on Pages F-1 through F-23.

EAST TEXAS AND NORTHWESTERN LOUISIANA

EAST TEXAS

     The East Texas properties are located in Harrison and Panola Counties,
Texas. These properties contain approximately 20,304 gross (17,917 net) acres
with rights covering the Travis Peak, Pettit, Glen Rose and Cotton Valley
formations. Our East Texas properties have 65.3 Bcfe of proved reserves or 98%
of our total proved reserves at December 31, 2002, of which 45.7 Bcfe is
classified as proved undeveloped.

     We have interests in 50 gross (37.6 net) producing wells in East Texas, of
which we operate 36. Average daily production net to our interest for 2002 was
4,466 Mcf of gas and 104 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

                                       12
<PAGE>

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 undeveloped reserves are significant in
this region consisting of 45.7 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.

     In 2001, GMX successfully drilled and completed ten wells on its East Texas
property. Most of these were dual completions, each well having two or more
separate producing reservoirs in either the Pettit, Travis Peak or Cotton Valley
geological formations from 6,000 to 10,000 feet deep. The dual completions have
the same effect as drilling 20 separate single zone wells. Annual production
volumes of oil and natural gas net to the Company's interest for 2002 was 1,858
Mmcfe compared with production in 2001 of 1,760 Mmcfe, a year-over-year increase
of 16 %. GMX owns a 100% working interest in each of the new East Texas wells.
The Company did not drill any wells in East Texas in 2002. For 2003, GMX
initially plans to drill eight wells in East Texas during 2003 subject to
availability of capital resources. The pace of future development of this
property will depend on availability of capital, future drilling results, the
general economic conditions of the energy industry and, on the price the Company
receives for the natural gas and crude oil produced. There is a potential for up
to 400 locations of Cotton Valley wells in our East Texas acreage assuming an
ultimate well density of 2 wells in each 80 acre tract.

     At December 31, 2002, Sproule Associates, Inc., our independent reserve
engineering firm, assigned a total of 19.2 Bcfe of proved reserves to the
completed East Texas wells and 45.7 Bcfe of proved undeveloped reserves to our
63 proved undeveloped locations in East Texas.

     Recent third party drilling in the vicinity of our development acreage also
confirms productive zones as shallow as 3700 feet in the Glenn Rose formation.
We expect several wells will target this zone, but we have yet to complete our
geological evaluation of this zone.

                                       13
<PAGE>

LOUISIANA

     The Louisiana properties are located in Clairborne, Caddo, Catahoula and
Webster parishes with production from the Cotton Valley, Hosston and Rodessa
formations. We have 6 gross (2.4 net) producing wells, 3 of which we operate.
Production is predominately oil. Louisiana proved reserves are .4 Bcfe and
represent approximately 1% of proved reserves as of December 31, 2002. Average
daily production net to our interest for 2002 was 6 Bbls of oil and 26 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 2,077 gross (1,821 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 represent 2% of our total proved reserves as of December 31, 2002.
Average daily production net to our interests for 2002 from our 7 gross (5.6
net) producing wells in this area was 36 Mcf of gas and 31 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 and we are considering 3D seismic evaluations of these
formations.

RESERVES

     As of December 31, 2002, Sproule Associates Inc. estimates our proved
reserves are 67 Bcfe. An estimated 20 Bcfe is expected to be produced from
existing wells and another 47 Bcfe or 70% of the proved reserves, is classified
as proved undeveloped. All of our proved undeveloped reserves are on locations
which are adjacent to wells productive in the same formations. As of December
31, 2002, we had interests in 56 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.










                                       14
<PAGE>

                                                   YEARS ENDED DECEMBER 31,
                                                 2000        2001        2002
                                                 ----        ----        ----
PROVED DEVELOPED:
Gas (MMcf)                                      15,352      21,932      16,501
Oil (MBbls)                                      1,410       1,018         604
                  Total (MMcfe)                 23,811      28,040      20,125
PROVED UNDEVELOPED:
Gas (MMcf)                                      33,718      46,679      40,181
Oil (MBbls)                                      2,448       2,844       1,060
                  Total (MMcfe)                 48,406      63,740      46,541
TOTAL PROVED:
Gas (MMcf)                                      49,070      68,611      56,683
Oil (MBbls)                                      3,858       3,862       1,663
                  Total (MMcfe)                 72,218      91,781      66,663

ESTIMATED FUTURE NET REVENUES (1)($000S)      $492,310    $155,678    $186,336

PRESENT VALUE(1)($000S)                       $284,161     $70,952     $80,614

----------------------
(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. The
     standardized measure of discounted future net cash flows as of 2000, 2001
     and 2002 was $186,201,000, $48,524,000, and $54,312,000 respectively.

     There was a significant decrease in proved reserves from December 31, 2001
to December 31, 2002. The sale of our Kansas properties which represented 9.6
Bcfe of proved reserves at December 31, 2001 accounted for some of this decline.
In addition, we produced 2.1 Bcfe which was not replaced due to absence of
drilling in 2002. Finally, our proved reserve estimates at December 31, 2002
were revised downward by 13.5 Bcfe compared to December 31, 2001 primarily as a
result of lower than expected production from our East Texas wells drilled in
2001.

     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 $37.5 million as of December 31, 2002, of which $11.8 million is
scheduled in the reserve report to be expended in 2003. We do not currently have
the resources to fund these development costs and, accordingly, there is
substantial uncertainty about our ability to develop these proved undeveloped
reserves in the time frame estimated in the reserve report. If we enter into
joint ventures or other arrangements to fund some or all of the development
costs, our interests in the reserves would likely be reduced. Accordingly, there
is no assurance we will be able to realize the value of our estimated proved
undeveloped reserves.

     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, 2002 were $28.98 per barrel for oil and
$4.62 per Mcf 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

                                       15
<PAGE>

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 $0.8 million and $2.6 million
respectively, as of December 31, 2002.

     Sproule Associates, Inc., our independent reserve engineers, prepared the
estimates of proved reserves as of December 31, 2002, 2001 and 2000.

     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 AND ACQUISITION AND DRILLING RESULTS

     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,
                                     -------------------------------------
                                        2000          2001         2002
                                     ----------   -----------   ----------
PROPERTY ACQUISITION COSTS:
         Proved                      $  359,753   $ 2,382,548   $  120,157
         Unproved                       335,259     2,488,614       84,672
DEVELOPMENT COSTS                     1,379,531    19,270,480    2,812,876
                                     ----------   -----------   ----------
         Total                       $2,074,543   $24,141,642   $3,017,705
                                     ==========   ===========   ==========

     We drilled or participated in the drilling of wells as set out in the table
below for the periods indicated. 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
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,
                             --------------------------------------------------
                                 2000               2001               2002
                             ------------       ------------       ------------
DEVELOPMENT WELLS:           Gross    Net       Gross    Net       Gross    Net
         Gas                    1       1         10      10         --      --
         Oil                   --      --          1      .5         --      --
         Dry                   --      --         --      --         --      --
                             ----    ----       ----    ----       ----    ----
                  Total         1       1         11    10.5         --      --
                             ====    ====       ====    ====       ====    ====

     The following table shows our developed and undeveloped oil and gas lease
and mineral acreage as of December 31, 2002. Excluded is acreage in which our
interest is limited to royalty, overriding royalty and other similar interests.

                                       16
<PAGE>

                                     DEVELOPED                UNDEVELOPED
                              -----------------------   -----------------------
LOCATION                        GROSS          NET        GROSS          NET
--------                      ----------   ----------   ----------   ----------
East Texas and Louisiana         13,045       12,450        6,818        5,163
Southeast New Mexico              1,760        1,504          317          317
                              ----------   ----------   ----------   ----------
         Total                   14,805       13,954        7,135        5,480
                              ==========   ==========   ==========   ==========

     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, 2002. Gross oil and gas wells include one well with multiple completions.
Wells with multiple completions are counted only once for purposes of the
following table.


                                                       PRODUCTIVE WELLS
                                                       ----------------
     TYPE OF WELL                                  GROSS              NET
     ------------                                  -----              ---
     Gas                                               36              29.5
     Oil                                               20              18.1
                                                -------------     -------------
              Total                                    56              42.6
                                                =============     =============


ITEM 3. LEGAL PROCEEDINGS

         On December 13, 2001, we terminated drilling contracts 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 we had issued to Nabors to secure our
payment obligation and counterclaimed for approximately $10,000,000 alleged to
be owed for an early termination fee and unpaid invoices. On December 20, 2002,
we received a jury verdict in our favor in our lawsuit against Nabors in the
United States District Court for the Western District of Oklahoma after a five
day trial. As a result of the jury verdict, the Company has no liability to
Nabors on its claim for approximately $10 million in contract termination
damages. In March

                                       17
<PAGE>

2003, Nabors filed a notice of appeal of the jury verdict. The appeal process is
likely to take more than 12 months and if Nabors is successful will likely
result in a new trial.

     As of the date of this report, the Company does not believe that a material
loss is probable. The continuing uncertainty with respect to the ultimate
outcome of the Nabors litigation has an adverse affect on our ability to raise
capital.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     There were no matters submitted during the fourth quarter of 2002 to a vote
of the shareholders.

                                     PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

     Effective June 22, 2001, we began trading on the NASDAQ National Market.
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
JUNE 22, 2001 TO JUNE 30, 2001
Common Stock                                      $  12.10             $  10.25
Class A warrants                                      4.35                 3.18
JULY 1, 2001 TO SEPTEMBER 30, 2001
Common Stock                                         10.70                 4.00
Class A warrants                                      3.35                 1.15
OCTOBER 1, 2001 TO DECEMBER 31, 2001
Common Stock                                          6.25                 3.78
Class A warrants                                      2.15                 0.70
JANUARY 1, 2002 TO MARCH 31, 2002
Common Stock                                          4.65                 2.40
Class A warrants                                      1.85                 0.60
APRIL 1, 2002 TO JUNE 30, 2002
Common Stock                                      $   3.80             $   2.06
Class A warrants                                      0.76                 0.32
JULY 1, 2002 TO SEPTEMBER 30, 2002
Common Stock                                      $   2.60             $   1.50
Class A warrants                                      0.32                 0.04
OCTOBER 1, 2002 TO DECEMBER 31, 2002
Common Stock                                      $   2.45             $   0.89
Class A warrants                                      0.22                 0.01

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

     As of April 9, 2003, there were 14 record owners of our Common Stock and
approximately 600 beneficial owners.

                                       18
<PAGE>

     Each Class A warrant entitles the holder to purchase one share of common
stock for $9.00 per share until March 12, 2002 and for $12.00 per share
thereafter until the warrants expire on February 12, 2006. We previously had
outstanding Class B warrants but these expired by their own terms on February
12, 2003 and have not been extended.

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















                                       19
<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,
                                                      --------------------------------------------
                                                          2000            2001            2002
                                                      ------------    ------------    ------------
STATEMENT OF OPERATIONS DATA:
<S>                                                   <C>             <C>             <C>
Oil and gas sales                                     $  4,153,934    $  5,898,003    $  5,970,792
Interest and other income                                   37,378         554,296          17,550
                                                      ------------    ------------    ------------
                  Total revenues                         4,191,312       6,452,299       5,988,342
                                                      ------------    ------------    ------------
Lease operations                                         1,207,095       1,604,559       1,324,481
Production and severance taxes                             260,064         338,637         382,826
General and administrative                                 578,641       1,855,736       2,577,388
Depreciation, depletion and amortization                   420,488       1,026,498       1,901,976
Interest                                                   664,713         359,118         510,472
                                                      ------------    ------------    ------------
                  Total expenses                      $  3,131,001    $  5,184,548    $  6,697,142
                                                      ------------    ------------    ------------
Income (loss) before income taxes                        1,060,311       1,267,751        (708,800)
Income tax expense (benefit)                                52,000         211,000        (263,000)
                                                      ------------    ------------    ------------
Net income (loss)                                     $  1,008,311    $  1,056,751    $   (445,800)
                                                      ============    ============    ============

Net income (loss) applicable to common shares         $    875,810    $  1,056,751    $   (445,800)
                                                      ============    ============    ============

Net income (loss) per share - basic                   $        .48    $        .21    $       (.07)
                                                      ============    ============    ============

Net income (loss) per share - diluted                 $        .29    $        .20    $       (.07)
                                                      ============    ============    ============

Weighted average common shares - basic                   1,822,926       5,148,493       6,550,000
                                                      ============    ============    ============

Weighted average common shares - diluted                 3,469,326       5,179,693       6,550,000
                                                      ============    ============    ============
STATEMENT OF CASH FLOWS DATA:
Net cash provided by (used in) operating activities   $  1,394,168    $  8,016,600    $ (2,547,639)
Net cash provided by (used in) investing activities     (2,177,335)    (26,700,785)      1,267,831
Net cash provided by financing activities                  277,997      18,657,867       1,820,000

BALANCE SHEET DATA (AT END OF PERIOD):
Oil and gas properties, net                           $  8,862,690    $ 32,148,615    $ 29,359,309
Total assets                                            10,970,282      36,719,674      33,319,432
Long-term debt, including current portion                7,573,864       6,280,000       8,100,000
Shareholders' equity                                     1,899,793      22,474,563      21,607,463
</TABLE>

                                       20
<PAGE>

SUMMARY OPERATING AND RESERVE DATA

     The following table presents an unaudited summary of certain operating and
oil and gas reserve data for the periods indicated.
<TABLE><CAPTION>
                                                                                    YEARS ENDED DECEMBER 31,
                                                                             --------------------------------------
                                                                               2000           2001           2002
                                                                             --------       --------       --------
PRODUCTION:
<S>                                                                               <C>            <C>            <C>
Oil production (MBbls)                                                             75             81             70
Natural gas production (MMcf)                                                     719          1,294          1,639
Equivalent production (MMcfe)                                                    1158          1,778          2,059

AVERAGE SALES PRICE:
Oil price (per Bbl)                                                          $  21.33(1)    $  24.86(1)$      23.48(1)
Natural gas price (per Mcf)                                                      3.57           3.01(1)        3.03(1)
                                                                             --------       --------       --------

AVERAGE SALES PRICE (PER MCFE)                                               $   3.59       $   3.33       $   3.22

OPERATING AND OVERHEAD COSTS (PER MCFE):
Lease operating expenses                                                     $   1.04       $    .90       $    .64
Production and severance taxes                                                    .36            .19            .19
General and administrative                                                        .50           1.05           1.25
                                                                             --------       --------       --------
         Total                                                               $   1.77       $   2.14       $   2.08
                                                                             --------       --------       --------

OPERATING MARGIN (PER MCFE)                                                  $   1.82       $   1.19       $   1.14

OTHER (PER MCFE):
Depreciation, depletion and amortization - oil and gas production            $    .36       $    .58       $    .92

ESTIMATED NET PROVED RESERVES (AS OF THE RESPECTIVE PERIOD-END):
Natural gas (Bcf)                                                                49.1           68.6           56.7
Oil (MMbls)                                                                       3.9            3.9            1.7
Total (Bcfe)                                                                     72.5           91.8           66.7
Estimated Future Net Revenues ($MM)(2)(3)                                       492.3          155.7          294.7
Present Value ($MM)(2)(3)                                                       284.2           71.0           80.6
Standardized measure of discounted future net cash flows ($mm)(4)               186.3           48.5           54.3
</TABLE>
-----------------------
(1)  Net of results of (i) hedging activities which reduced the average oil
     price in 2000 by $8.91 per Bbl and increased the average oil price in 2001
     by $.95 per Bbl and (ii) gas hedging activities which reduced the average
     gas price in 2001 by $.14 per Mcf and $.40 per Mcf in 2002.

(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

                                       21
<PAGE>

     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.

CRITICAL ACCOUNTING POLICIES

     In December 2001, the Securities and Exchange Commission encouraged public
companies to include in their annual report information on critical accounting
policies. These policies have been defined as those that are very important to
the portrayal of the Company's financial condition and results, and require
management's most difficult, subjective or complex judgments.

     Below is what GMX believes is its critical accounting policy.

FULL COST CALCULATIONS

     GMX follows the full cost method of accounting for its oil and natural gas
properties. 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 GMX's capitalized costs are in excess of the calculated
ceiling, the excess must be written off as an expense.

     GMX's discounted present value of estimated future net revenues from its
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 GMX's 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 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.

                                       22
<PAGE>

     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 GMX's
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 GMX's long-term
price forecast that is a barometer for true fair value. 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.

     There is an acceptable alternative method for accounting for oil and gas
properties under generally accepted accounting principles which is referred to
as the "successful efforts" method of accounting. Under this method, costs
associated with unsuccessful exploratory drilling efforts are immediately
expensed, and costs for successful exploratory wells and all development costs
are capitalized and amortized over the future production period on a field by
field basis. Properties are also tested at the end of each accounting period for
impairment on a field by field basis using a method similar to the calculation
of the full cost ceiling limitation. We have selected the full-cost method of
accounting as opposed to the successful efforts method because we believe that
the full-cost method fully measures the complete costs associated with the
acquisition, exploration, exploitation, and development of oil and gas
properties, particularly the capitalization of general and administrative costs
directly related to our drilling efforts. While we have not historically drilled
exploratory wells, we may do so in the future. We consider that the costs of
drilling unsuccessful exploratory wells would be a part of our overall costs to
find and develop reserves, so the use of the full-cost method is consistent with
how we would evaluate our results.

RESULTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2002 COMPARED TO YEAR
ENDED DECEMBER 31, 2001

     OIL AND GAS SALES. Oil and gas sales in the year ended December 31, 2002
increased 1% to $5,970,792 compared to the year ended December 31, 2001, due to
increased production. The average price per barrel of oil and mcf of gas
received in 2002 was $23.48 and $3.03, respectively, compared to $24.86 and
$3.01 in the year of 2001. During 2002, the company hedged 900,000 Mcf of gas
through price swap agreements with a fixed price of $2.664 per Mcf. The price
swap agreements reduced sales by $652,100. Oil production for 2002 decreased
because of the September 2002 sale of Kansas properties. Gas production
increased to 1,639 MMcf compared to 1,294 MMcf for the year of 2001, an increase
of 27%. Increased production in 2002 resulted from new production from wells
drilled in 2001 and the reworking of certain wells.

                                       23
<PAGE>

     LEASE OPERATIONS. Lease operations expense decreased $280,078 in 2002 to
$1,324,481 a 17% decrease compared to 2001. Decreased expenses resulted from the
sale of Kansas properties. Lease operations expense on an equivalent unit of
production basis was $0.64 per Mcfe in 2002 compared to $0.90 per Mcfe for 2001,
primarily from the decreased oil production and the full year effect of the
higher volume gas wells drilled in 2001.

     PRODUCTION AND SEVERANCE TAXES. Production and severance taxes increased
13% to $382,826 in 2002 compared to $338,637 in 2001. 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
increased oil and gas sales.

     DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization expense increased $875,478 to $1,901,976 in 2002, up 85% from 2001.
This increase is due primarily to an increase in the depletion rate for 2002
from the drilling of new wells in 2001 when drilling costs were high. The oil
and gas depreciation, depletion and amortization rate per equivalent unit of
production was $0.92 per Mcfe in 2002 compared to $0.58 per Mcfe in 2001.

     INTEREST. Interest expense for the year 2002 was $510,472 compared to
$359,118 for the year of 2001. This increase is primarily attributable to higher
average long term debt balances outstanding during 2002.

     GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense for
2002 was $2,577,388 compared to $1,855,736 for 2001, an increase of 39%. This
increase of $721,652 was the result of an increase in salaries and payroll
expenses of $259,000 and an increase in legal and professional fees primarily in
connection with the Nabors Drilling lawsuit of $363,000 and other general and
administrative expenses of $99,000. The salary increase was a result of an
increase in administrative personnel. General and administrative expense per
equivalent unit of production was $1.25 per Mcfe for the 2002 period compared to
$1.05 per Mcfe for the comparable period in 2001. In late 2002, we reduced
personnel and accordingly expect salaries and payroll expense to decline in
2003. We expect to continue to incur legal fees for the Nabors drilling appeal
but these costs should be significantly less than pre-trial and trial expenses.

     INCOME TAXES. Income tax benefit for year of 2002 was $263,000 as compared
to an expense of $211,000 in 2001. This decrease resulted from the Company's net
loss incurred in 2002.

RESULTS OF OPERATIONS--YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED
DECEMBER 31, 2000

     OIL AND GAS SALES. Oil and gas sales increased in 2001 as a result of an
increase in production. Gas production increased to 1294 MMcf compared to 719
MMcf for the year of 2000, an increase of 80%. Increased production in the year
of 2001 resulted from new production from wells drilled in 2001. Oil production
for 2001 was 81 MMbls compared to 75 MMbls in the year of 2000, an increase of
8%. The average prices per barrel of oil and mcf of gas received in 2001 were
$24.86 and $3.01, respectively, compared to $21.33 and $3.57 in the

                                       24
<PAGE>

year of 2000. During the year of 2000, the company hedged 60,000 Bbls of oil
through price swap agreements with a fixed price of $20.25 per bbl. The price
swap agreements reduced sales revenues in 2000 by $596,970. During the year
2001, the company hedged 80,000 mcf of gas through price swap agreements with a
fixed price of $4.70 per mcf. The effects of these price swap agreements reduced
sales revenues for 2001 by $179,865.

     LEASE OPERATIONS. Lease operations expense increased $397,464 in the year
of 2001 to $1,604,559, a 33% increase compared to 2000. Increased expense
resulted from additional producing wells. Lease operations expense on an
equivalent unit of production basis was $.90 per Mcfe in 2001 compared to $1.04
per Mcfe for 2000. This decrease resulted from an increase in production.

     PRODUCTION AND SEVERANCE TAXES. Production and severance taxes increased
30% to $338,637 in the year of 2001 compared to $260,063 in the year of 2000.
Production and severance taxes are assessed on the value of the oil and gas
produced. As a result, the increase resulted primarily from increased oil and
gas sales as described above.

     DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization expense increased $606,010 to $1,026,498 in the year 2001, up 144%
from the year of 2000. This increase is due primarily to higher production
levels along with an increase in the depletion rate for 2001. The oil and gas
depreciation, depletion and amortization rate per equivalent unit of production
was $.58 per Mcfe in 2001 compared to $.30 per Mcfe in 2000. The depletion rate
increased primarily from the effects of wells completed during 2001 that
increased reserves.

     INTEREST. Interest expense for the year 2001 was $359,118 compared to
$664,713 for the year of 2000. This decrease is primarily attributable to the
decrease in the average long term debt balance outstanding during 2001, coupled
with the decline in the average interest rates.

     GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense for
the year 2001 was $1,855,736 compared to $578,641 for the year of 2000, an
increase of 221%. This increase was the result of an increase in salaries of
$423,001, investor relations expense of $305,280, legal and professional of
$190,026, and an increase in other general and administrative expenses of
$358,788. The salary increase was a result of an increase in administrative
salaries due to the addition of administrative personnel. Investor relations and
a portion of legal and professional increases resulted from the Company being a
public company in 2001. The remainder of legal and professional cost increases
resulted from various litigation matters. General and administrative expense per
equivalent unit of production was $1.05 per Mcfe for 2001 compared to $.50 per
Mcfe for the comparable period in 2000. We expect general and administrative
expense to decline on a unit of production basis as our production increases.

     INCOME TAXES. Income tax expense for year of 2001 was $211,000 compared to
$52,000 for 2000. This increase resulted from increased net income in 2001
compared to 2000. Additionally, permanent differences associated with statutory
depletion deduction in excess of cost depletion reduced the Company's effective
tax rate from an expected statutory rate of 38% to our effective tax rate of
17%.

                                       25
<PAGE>

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 flows from
financing activities are also a significant source of funding. Prior to the
completion of our public offerings in February 2001 and July 2001, we had relied
heavily upon the availability under our revolving bank credit facility and from
drilling advances from outside investors.

     On February 12, 2001, we completed our initial public offering of 1,250,000
units with net proceeds of approximately $8.5 million. In July, 2001, we sold an
additional 2,300,000 common shares at a price of $5.50 per share through a
secondary public offering with net proceeds of approximately $11.3 million. By
December 31, 2001, these proceeds had been fully used, primarily for development
drilling. As a result of uncertainties relating to pending litigation with a
former drilling contractor, at December 31, 2001 we were unable to obtain
additional advances to drill or for other purposes and were in default under the
terms of our credit facility. Due to these liquidity considerations there
existed uncertainties about our ability to continue operating as a going concern
and our independent auditor included an explanatory paragraph in their audit
opinion on our 2001 financial statements . We did not engage in any development
activity in 2002. At December 31, 2002, we remained in technical default under
our credit facility (which matures on May 1, 2003) and we had a significant
working capital deficit. As a result, our audit report for December 31, 2002
continues to have a going concern explanatory paragraph. See "Liquidity and
Financing Considerations."

CASH FLOW--YEAR ENDED DECEMBER 31, 2002 COMPARED TO YEAR ENDED DECEMBER 31, 2001

     In 2002 we had a deficit cash flow from operating activities of $2,547,639
as a result of reductions in net income and from payments of 2001 accounts
payable during 2002. Our cash flow from operating activities in 2001 was
$8,016,600 primarily due to 2001 net income and increases in accounts payable of
$6,301,732. We received a net $1,267,831 in cash from investing activities in
2002 compared to net cash expenditures of $26,700,785 in 2001. 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.

CASH FLOW--2001 COMPARED TO 2000

     In the year ended December 31, 2001 and 2000, we spent $26,700,785 and
$2,177,335, respectively, in oil and gas acquisitions and development
activities. These investments were funded for the year ended December 31, 2001
by proceeds of our public offerings and $8,016,600 of net cash provided by
operations.

                                       26
<PAGE>

CREDIT FACILITY

     On October 31, 2000, we entered into a secured credit facility provided by
Local Oklahoma Bank, N.A., which replaced our prior credit facility. The new
credit facility provides 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 was initially $7.25
million at October 31, 2000, but was later increased to $10 million.

     On May 28, 2002, the credit facility was amended to increase the Borrowing
Base to $12,500,000 subject to monthly commitment reductions. Monthly commitment
reductions were $172,000 for June and July 2002. Beginning August 1, 2002, and
continuing until the next Borrowing Base determination (September 1, 2002),
monthly commitment reductions were $172,000 plus any positive difference between
the $172,000 and 80% of "Net Cash Flow" (net income before income taxes plus
non-cash expenses) for the second preceding month. The scheduled September 1,
2002 Borrowing Base determination was not made and since that time we have been
dedicating all available cash flow to repay the credit facility.

     As of December 31, 2002, we had $8.1 million outstanding under the
facility. As of March 1, 2003, our Borrowing Base has been redetermined by the
bank to be $5,846,000 and we had $8.07 million outstanding. We are unable to
reduce the amount of our indebtedness to this level, so this event constitutes
an additional default. The promissory note matures on May 1, 2003.

     Borrowings bear interest at the prime rate plus 1%. 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 monthly debt service coverage ratio of at
          least 1.1 to 1. 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 monthly principal
          reduction requirements plus interest.

     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 more than $100,000.

                                       27
<PAGE>

     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.

     We are in default of the adjusted current ratio and debt service coverage
covenants as of December 31, 2002. In addition, as described above, our debt
amount exceeds the Borrowing Base by approximately $2.2 million as of March 1,
2003. As a result of these defaults which have not been waived as of April 10,
2003 and the May 1, 2003 maturity date, the liability owed to the bank under the
credit facility has been classified as current liability as of December 31,
2002. As of April 10, 2003, the bank had not demanded repayment of this
borrowing, and since December 31, 2002, we have continued to dedicate all
available cash flow to debt repayment. As a result of the expiration of gas
price swap agreements and increases in commodity prices, we are experiencing
some improvement in cash flow in the first quarter of 2003, but it is still
insufficient to pay the debt.

WORKING CAPITAL

     At December 31, 2002, we had a working capital deficit of $10,085,779.
Excluding our bank debt, our working capital deficit as of December 31, 2002
would have been $1,985,779. Total long-term debt outstanding at December 31,
2002 was $8.1 million, representing 27% of our total capitalization.

COMMITMENTS AND CAPITAL EXPENDITURES

     Other than obligations under our credit facility, our commitments for
capital expenditures relate to development of oil and gas properties. We have
not entered 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.

     During 2001 and early 2002, we drilled and completed 10 wells in East Texas
using the proceeds from our public offerings and borrowings under our credit
facility. These wells were drilled to depths ranging from 6,000 to 8,500 feet.
Costs on these wells varied from $1.2 million to $2.8 million depending on the
numbers of producing zones completed in each well. We did not drill any new
wells in 2002 because of the absence of capital resources. Additional sources of
financing will likely be necessary in 2003 to continue this drilling plan which
could be provided by additional borrowings, sales of equity securities or
through joint venture or similar arrangements with industry partners. We are
exploring various alternative financing sources. Until such financing is
available, our drilling activities will be significantly curtailed.

                                       28
<PAGE>

LIQUIDITY AND FINANCING CONSIDERATIONS

     As described elsewhere herein, we are currently in default under our bank
credit facility and have a working capital deficit which in turn has resulted in
the inclusion of a going concern explanatory paragraph in their auditors' report
on our 2002 financial statements. The bank had not demanded payment as of April
10, 2003. The debt matures on May 1, 2003 and it is possible that the bank will
seek to enforce collection after that date or take other actions that may
restrict our ability to operate. While we were successful at the trial court in
our litigation with Nabors, the appeal of this decision has resulted in
continuing uncertainty about exposure to Nabors. We sold a portion of our proved
producing and proved undeveloped reserves in Kansas in 2002 to reduce debt and
accounts payable. We are pursuing all available alternatives to find alternative
sources of capital or to seek a merger or acquisition or other transaction that
will enable us to meet our obligations. We may also enter into development
arrangements with other industry participants to fund development of our
properties. These arrangements would reduce or eliminate our capital costs and
our interest in any future revenues. There can be no assurance that we will be
able to enter into any of these financial arrangements. We expect that our
current cash flow, depending on oil and gas prices, will be sufficient to meet
current operating expenses pending resolution of our strategic alternatives.
However, until all of these uncertainties are resolved, we will not be able to
pursue any further drilling and our financial condition and liquidity will
remain uncertain.

PRICE RISK MANAGEMENT

     We have entered into, and expect to periodically enter into, financial
price risk management activities with respect to a portion of projected oil and
gas production through financial price swaps whereby we receive 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, but we do not expect to manage at any time
more than 75% of our total production. The gains and losses realized as a result
of these activities are substantially offset in the cash market when the
commodity is delivered. For the year ended December 31, 2001, we hedged 20,000
MMBtu of natural gas per month at a fixed price of $4.70 per MMBtu. These
arrangements hedged approximately 34% of our estimated monthly gas production
based on our December 31, 2000 reserve report. We settled an oil price swap
agreement covering the first six months of 2001 in December 2000 for a gain of
$76,334 which was amortized into income during 2001 over the original term of
the oil price swap agreement. During 2002, we have entered into price swap
agreements for 50,000 and 40,000 MMBtu of natural gas per month at a fixed price
of $2.66 and $2.67 per MMBtu, respectively. These arrangements managed
approximately 52% of our estimated monthly gas production based on our December
31, 2001 reserve report. This hedge reduced our average realized gas price from
$3.43 to $3.03 per Mcf.

                                       29
<PAGE>

IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED

     In July 2001, the Financial Accounting Standards Board issued SFAS 143,
"Accounting for Asset Retirement Obligations." SFAS 143 requires entities to
record the fair value of a liability for an asset retirement obligation in the
period in which it is incurred and a corresponding increase in the carrying
amount of the related long-lived asset. SFAS 143 is effective for fiscal years
beginning after June 15, 2002. The Company has not calculated the impact of this
statement on its reported results.

     In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections,
that, among other things, rescinded SFAS No. 4, Reporting Gains and Losses from
Extinguishment of Debt. With the rescission of SFAS No. 4, the early
extinguishment of debt generally will no longer be classified as an
extraordinary item for financial statement presentation purposes. The provision
is effective for fiscal years beginning after May 15, 2002. The Company does not
anticipate that the adoption of SFAS No. 145 will have a material effect on its
financial position or results of operations.

     In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities, which replaces Emerging Issues Task Force
Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits
and Other Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring). The new standard required companies to recognize costs
associated with exit or disposal activities when they are incurred rather than
at the date of a commitment to an exit or disposal plan. The statement is to be
applied prospectively to exit or disposal activities initiated after December
31, 2002. The Company does not anticipate that the adoption of SFAS No. 146 will
have a material effect on its financial position or results of operations.

     In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based
Compensation - Transition and Disclosure, which amended SFAS No. 123, Accounting
for Stock-Based Compensation. The new standard provides alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. Additionally, the statement amends the
disclosure requirements of SFAS No. 123 to require prominent disclosures in the
annual and interim financial statements about the method of accounting for
stock-based employee compensation and the effect of the method used in reported
results. This statement is effective for financial statements for fiscal years
ending after December 15, 2002. In compliance with SFAS No. 148, the Company has
elected to continue to follow the intrinsic value method in accounting for its
stock-based employee compensation arrangement as defined by APB No. 25.

     In November 2002, the FASB issued Interpretation No. 45 (FIN 45),
Guarantor's Accounting and Disclosure Requirement for Guarantees, Including
Indirect Guarantees of Indebtedness of Others. For a guarantee subject to FASB
Interpretation No. 45, a guarantor is required to measure and recognize the fair
value of the guarantee liability at inception. For many guarantees, fair value
will likely be determined using the expected present value method described in
FASB Concepts Statement 7, Using Cash Flow Information and Present Value in

                                       30
<PAGE>

Accounting Measurements. In addition, FIN 45 provides new disclosure
requirements. The disclosure requirements of FIN 45 were effective for the
Company as of December 31, 2002. The measurement and liability recognition
provisions are applied prospectively to guarantees or modifications after
December 31, 2002. The Company anticipates that FIN 45 will not have a material
impact on the Company's financial statements.

     In January 2003, the FASB issued Interpretation No. 46, Consolidation of
Variable Interest Entities (FIN 46). Subject to certain criteria defined in the
Interpretation, FIN 46 will require consolidation by business enterprises of
variable interest entities if the enterprise has a variable interest that will
absorb the majority of the entity's expected losses, receives a majority of its
expected returns, or both. The provisions of FIN 46 are effective immediately
for interests acquired in variable interest entities after January 31, 2003, and
at the beginning of the first interim or annual period beginning after June 15,
2003, for interests acquired in variable interest entities before February 1,
2003 (for the Company in the third quarter of 2003). The Company anticipates
that FIN 46 will not have a material impact on the Company's financial
statements.

FORWARD-LOOKING STATEMENTS

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

     The forward looking statements in this report are subject to all the risks
and uncertainties which are described in this document. We may also make
material acquisitions or divestitures or enter into financing transactions. None
of these events can be predicted with certainty or 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.

                                       31
<PAGE>

RISK FACTORS RELATED TO GMX

THERE ARE SUBSTANTIAL UNCERTAINTIES ABOUT OUR CURRENT FINANCIAL CONDITION WHICH
CURTAIL OUR ABILITY TO CONDUCT FURTHER DRILLING AND MAY AFFECT OUR ABILITY TO
CONTINUE OPERATING AS A GOING CONCERN.

     As discussed above, we are in default on our bank debt and our ability to
continue operating as a going concern due to liquidity considerations is
uncertain. In the absence of asset sales or other sources of financing, we are
unable to pay our bank debt and pay past due accounts payable. In addition, we
do not have the financial resources to pursue further drilling and, accordingly,
we may not be able to realize the value of our proved undeveloped reserves.
Until these uncertainties are resolved, our ability to implement our business
plan will be materially adversely affected and our financial condition will be
impaired.

THERE IS LITIGATION PENDING THAT MAY HAVE A MATERIAL ADVERSE EFFECT ON THE
COMPANY IF ADVERSELY DETERMINED.

     We filed a lawsuit in the United States District Court for the Western
District of Oklahoma against Nabors Drilling USA relating to the drilling
contracts between us and Nabors. Nabors filed a counterclaim against us. We have
received a jury verdict in our favor on December 20, 2002. On March 3, 2003,
Nabors filed a notice of appeal. If this action is adversely determined, it
could have a material adverse effect on the Company. See "Item 3. Legal
Proceedings".

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

     Ken L. Kenworthy, Jr. and Ken L. Kenworthy, Sr. beneficially own
approximately 31% and 15% respectively, of our outstanding common stock. These
shareholders, acting together, will be able to control 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.

                                       32
<PAGE>

WE HAVE LIMITED OPERATING HISTORY.

     We were organized in 1998 and have been in operation for less than five
years. Our limited operating history may not be indicative of our future
prospects. We face all of the risks inherent in a new business, including:

     o    the risk that we will be unable to implement our business plan and
          achieve our expected financial results;

     o    the risk that we will be unable to manage growth in our operations by
          adding personnel, systems and practices necessary to operate a larger
          business; and

     o    the risk that, as a small business, we will be subject to market,
          environmental, regulatory and other developments that we cannot either
          foresee or control as well as can larger or more established
          businesses.

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 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 majority of our common stock, the Kenworthys have
appointed the current directors and will have the power to remove and replace
directors.

HEDGING OUR PRODUCTION MAY RESULT IN LOSSES OR LIMIT POTENTIAL GAINS.

     To reduce our exposure to fluctuations in the prices of oil and natural
gas, we have in the past, and may in the future, enter into hedging
arrangements. 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.

                                       33
<PAGE>

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 do not expect 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. We
currently are not able to make the necessary capital investment to maintain or
expand our oil and natural gas reserves. 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 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.

RISKS RELATED TO THE OIL AND GAS INDUSTRY

A SUBSTANTIAL DECREASE IN OIL AND NATURAL GAS PRICES WOULD HAVE A MATERIAL
IMPACT ON US.

     Our future financial condition and results of operations are dependent upon
the prices we receive for our oil and natural gas production. Oil and natural
gas prices historically have been volatile and likely will continue to be
volatile in the future. This price volatility also affects our common stock
price. In 2001, we received gas and oil prices at the wellhead ranging from
$2.22 to $9.48 per Mcf and $17.88 to $29.18 per Bbl. In 2002, we received gas
and oil prices ranging from $1.23 to $4.68 per Mcf and $15.78 to $29.16 per Bbl.
We cannot predict oil and natural gas prices and prices may decline in the
future. The following factors have an influence on oil and natural gas prices:

     o    relatively minor changes in the supply of and demand for oil and
          natural gas;

     o    storage availability;

                                       34
<PAGE>

     o    weather conditions;

     o    market uncertainty;

     o    domestic and foreign governmental regulations;.

     o    the availability and cost of alternative fuel sources;

     o    the domestic and foreign supply of oil and natural gas;

     o    the price of foreign oil and natural gas;

     o    political conditions in oil and natural gas producing regions,
          including the Middle East; and

     o    overall economic conditions.


WE MAY ENCOUNTER DIFFICULTY IN OBTAINING EQUIPMENT AND SERVICES.

     Higher oil and gas prices and increased oil and gas drilling activity, such
as those we experienced in 2000, generally stimulate increased demand and result
in increased prices and unavailability for drilling rigs, crews, associated
supplies, equipment and services. While we are currently experiencing no
difficulty obtaining drilling rigs, crews, associated supplies, equipment and
services because of a recent decrease in prices and in activity, such difficulty
could occur in the future. These shortages could also result in increased costs,
delays in timing of anticipated development or cause interests in oil and gas
leases to lapse. We cannot be certain that we will be able to implement our
drilling plans or at costs that will be as estimated or acceptable to us.

ESTIMATING OUR RESERVES FUTURE NET CASH FLOWS IS DIFFICULT TO DO WITH ANY
CERTAINTY.

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

                                       35
<PAGE>

     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.

     Our proved undeveloped reserve estimates are based on the assumption that
we can fund the associated development costs. Our ability to fund those costs in
the time frames assumed is uncertain and, accordingly, we may not be able to
realize the estimated value our proved undeveloped reserves.

WE MAY INCUR WRITE-DOWNS OF THE NET BOOK VALUES OF OUR OIL AND GAS PROPERTIES
WHICH WOULD ADVERSELY AFFECT OUR SHAREHOLDERS' EQUITY AND EARNINGS.

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

OPERATIONAL RISKS IN OUR BUSINESS ARE NUMEROUS AND COULD MATERIALLY IMPACT US.

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

     o    the presence of unanticipated pressure or irregularities in
          formations;

     o    accidents;

     o    title problems;

     o    weather conditions;

     o    compliance with governmental requirements; and

     o    shortages or delays in the delivery of equipment.

                                       36
<PAGE>

     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 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.

                                       37
<PAGE>

     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 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.

                                       38
<PAGE>

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.


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

     Not applicable.

                                    PART III


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

     The information required under item 9 will be contained in our definitive
proxy statement for the 2003 Annual Meeting of Shareholders and is incorporated
by reference. The proxy statement will be filed pursuant to Regulation 14A with
the Securities and Exchange Commission not later than 120 days after December
31, 2002.


ITEM 10. EXECUTIVE COMPENSATION

     The information required under item 10 will be contained in the proxy
statement for the 2003 Annual Meeting of Shareholders and is incorporated herein
by reference.

                                       39
<PAGE>

ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERSHIP AND MANAGEMENT.

     The information required under item 11 will be contained in the proxy
statement for the 2003 Annual Meeting of Shareholders and is incorporated herein
by reference.


ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     The information required under item 12 will be contained in the proxy
statement for the 2003 Annual Meeting of Shareholders and is incorporated herein
by reference.


ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K

     (a) The following documents are filed as part of this report:

     1. Exhibits: The following documents are filed as exhibits to this
     report, all of which have been previously filed and are incorporated by
     reference.

     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       Bylaws of GMX RESOURCES INC. (Incorporated by reference to
               Exhibit 3.2 to the Registration Statement on Form SB-2, File No.
               333-49328)

     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-Q for the
               quarter ended June 30, 2002)

                                       40
<PAGE>

     10.3(c)   Third Amendment to Credit Agreement dated August 16, 2002

     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)

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

     *         Management contracts or compensatory plan.

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

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

     (b) The Company filed a report on Form 8-K dated September 26, 2002
         reporting the sales of its Kansas oil and gas properties.

Item 14. CONTROLS AND PROCEDURES

     The Company's Chief Executive Officer and Chief Financial Officer
(collectively, the "Certifying Officers") are responsible for establishing and
maintaining disclosure controls and procedures. Based on a review of such
controls and procedures within 90 days of the date of this report, such officers
have concluded that the Company's disclosure controls and procedures are
effective to ensure that information required to be disclosed by the Company in
this report is accumulated and communicated to allow timely decisions regarding
required disclosure.

     The Certifying Officers also have indicated that there were no significant
changes in the Company's internal controls or other factors subsequent to the
date of their evaluation that could significantly affect such controls as of the
date of this report.








                                       41
<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.


                                           GMX RESOURCES INC.


Dated:   April 14, 2003                    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              April 14, 2003
-------------------------
Ken L. Kenworthy, Jr.


/s/ Ken Kenworthy, Sr.        Executive Vice President, Chief     April 14, 2003
-------------------------     Financial Officer and Director
Ken Kenworthy, Sr.


/s/ Steven Craig              Director                            April 14, 2003
-------------------------
Steven Craig


/s/ T. J. Boismier            Director                            April 14, 2003
-------------------------
T. J. Boismier




                                       42
<PAGE>

                                 CERTIFICATIONS
                                 --------------

I, Ken L. Kenworthy, Jr., certify that:

1.   I have reviewed this annual report on Form 10-KSB of GMX Resources Inc;;

2.   Based on my knowledge, this annual report does not contain any untrue
     statement of a material fact or omit to state a material fact necessary to
     make the statements made, in light of the circumstances under which such
     statements were made, not misleading with respect to the period covered by
     this annual report;

3.   Based on my knowledge, the financial statements, and other financial
     information included in this annual report, fairly present in all material
     respects the financial condition, results of operations and cash flows of
     the registrant as of, and for, the periods presented in this annual report;

4.   The registrant's other certifying officers and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

     a)   designed such disclosure controls and procedures to ensure that
          material information relating to the registrant, including its
          consolidated subsidiaries, is made known to us by others within those
          entities, particularly during the period in which this annual report
          is being prepared.

     b)   evaluated the effectiveness of the registrant's disclosure controls
          and procedures as of a date within 90 days prior to the filing date of
          this annual report (the Evaluation Date"); and

     c)   presented in this annual report our conclusions about the
          effectiveness of the disclosure controls and procedures based on our
          evaluation as of the Evaluation Date;

5.   The registrant's other certifying officers and I have disclosed, based on
     our most recent evaluation, to the registrant's auditors and the audit
     committee of the registrant's board of directors (or persons performing the
     equivalent functions):

     a)   all significant deficiencies in the design or operation of internal
          controls which could adversely affect the registrant's ability to
          record, process, summarize and report financial data and have
          identified for the registrant's auditors any material weaknesses in
          internal controls; and

     b)   any fraud, whether or not material, that involves management or other
          employees who have a significant role in the registrant's internal
          controls; and

6.   The registrant's other certifying officers and I have indicated in this
     annual report whether or nor there were any significant changes in internal
     controls or in other factors that could significantly affect internal
     controls subsequent to the date of our most recent evaluation, including
     and corrective actions with regard to significant deficiencies and material
     weaknesses.




Date: April 14, 2003                     /s/ Ken L. Kenworthy, Jr.
                                         -----------------------------
                                         Ken L. Kenworthy, Jr., President and
                                         Chief Executive Officer


                                       43
<PAGE>

                                 CERTIFICATIONS
                                 --------------

I, Ken L. Kenworthy, Sr., certify that:

1.   I have reviewed this annual report on Form 10-KSB of GMX Resources Inc;;

2.   Based on my knowledge, this annual report does not contain any untrue
     statement of a material fact or omit to state a material fact necessary to
     make the statements made, in light of the circumstances under which such
     statements were made, not misleading with respect to the period covered by
     this annual report;

3.   Based on my knowledge, the financial statements, and other financial
     information included in this annual report, fairly present in all material
     respects the financial condition, results of operations and cash flows of
     the registrant as of, and for, the periods presented in this annual report;

4.   The registrant's other certifying officers and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

     a)   Designed such disclosure controls and procedures to ensure that
          material information relating to the registrant, including its
          consolidated subsidiaries, is made known to us by others within those
          entities, particularly during the period in which this annual report
          is being prepared.

     b)   Evaluated the effectiveness of the registrant's disclosure controls
          and procedures as of a date within 90 days prior to the filing date of
          this annual report (the Evaluation Date"); and

     c)   Presented in this annual report our conclusions about the
          effectiveness of the disclosure controls and procedures based on our
          evaluation as of the Evaluation Date;

5.   The registrant's other certifying officers and I have disclosed, based on
     our most recent evaluation, to the registrant's auditors and the audit
     committee of the registrant's board of directors (or persons performing the
     equivalent functions):

     a)   all significant deficiencies in the design or operation of internal
          controls which could adversely affect the registrant's ability to
          record, process, summarize and report financial data and have
          identified for the registrant's auditors any material weaknesses in
          internal controls; and

     b)   any fraud, whether or not material, that involves management or other
          employees who have a significant role in the registrant's internal
          controls; and

6.   The registrant's other certifying officers and I have indicated in this
     annual report whether or nor there were any significant changes in internal
     controls or in other factors that could significantly affect internal
     controls subsequent to the date of our most recent evaluation, including
     and corrective actions with regard to significant deficiencies and material
     weaknesses.





Date: April 14, 2003                     /s/ Ken L. Kenworthy, Sr.
                                         --------------------------------
                                         Ken L. Kenworthy, Sr., Executive Vice
                                         President and Chief Financial Officer


                                       44
<PAGE>

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Independent Auditors' Report                                               F-2

Consolidated Balance Sheets, December 31, 2001 and 2002                    F-3

Consolidated Statements of Operations,
         Years Ended December 31, 2001 and 2002                            F-4

Consolidated Statements of Changes in Shareholders' Equity,
         Years Ended December 31, 2001 and 2002                            F-5

Consolidated Statements of Cash Flows,
         Years Ended December 31, 2001 and 2002                            F-6

Notes to Consolidated Financial Statements                                 F-7




























                                      F-1
<PAGE>


                          INDEPENDENT AUDITORS' REPORT


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, 2001 and 2002 and the related
consolidated statements of operations, changes in shareholders' equity, and cash
flows for the years then ended. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. 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, 2001 and 2002 and the results of their
operations and their cash flows for the years then ended, in conformity with
accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the
Company will continue operating 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.

As discussed in Note A to the consolidated financial statements, GMX Resources
Inc. changed its method of accounting for derivative instruments and hedging
activities in 2001.


                                                                       KPMG LLP

Oklahoma City, Oklahoma
April 14, 2003

                                      F-2
<PAGE>

                               GMX RESOURCES INC.
                           CONSOLIDATED BALANCE SHEETS
                           DECEMBER 31, 2001 AND 2002

<TABLE><CAPTION>
                                                                                     2001              2002
                                                                                 ------------      ------------
<S>                                                                              <C>               <C>
                                     ASSETS

CURRENT ASSETS:
       Cash and cash equivalents                                                 $      3,725      $    543,917
       Accounts receivable--interest owners                                           194,180            52,576
       Accounts receivable--oil and gas revenues                                    1,116,930           513,898
       Inventories                                                                    243,799           236,704
       Prepaid expenses and other current assets                                       98,512            11,609
                                                                                 ------------      ------------
                         Total current assets                                       1,657,146         1,358,704
                                                                                 ------------      ------------

OIL AND GAS PROPERTIES, AT COST, BASED ON THE FULL COST METHOD OF
   ACCOUNTING FOR OIL AND GAS PROPERTIES                                           34,113,269        32,881,893
       Less accumulated depreciation, depletion, and amortization                  (1,964,654)       (3,522,584)
                                                                                 ------------      ------------
                                                                                   32,148,615        29,359,309
                                                                                 ------------      ------------

OTHER PROPERTY AND EQUIPMENT                                                        3,159,963         3,200,345
       Less accumulated depreciation                                                 (317,302)         (656,572)
                                                                                 ------------      ------------
                                                                                    2,842,661         2,543,773
                                                                                 ------------      ------------

OTHER ASSETS                                                                           71,252            57,646
                                                                                 ------------      ------------

                         TOTAL ASSETS                                            $ 36,719,674      $ 33,319,432
                                                                                 ============      ============

                      LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
       Accounts payable                                                          $  6,880,869      $  2,426,715
       Accrued expenses                                                               185,763            81,855
       Accrued interest                                                                26,791             6,764
       Revenue distributions payable                                                  304,291           407,849
       Derivative instruments                                                              --           421,300
       Current portion of long-term debt                                            6,280,000         8,100,000
                                                                                 ------------      ------------
                         Total current liabilities                                 13,677,714        11,444,483

LONG-TERM DEBT, LESS CURRENT PORTION                                                       --                --

OTHER LIABILITIES                                                                     304,397           267,486

DEFERRED INCOME TAXES                                                                 263,000                --

SHAREHOLDERS' EQUITY:
       Common stock, par value $.001 per share--authorized 50,000,000 shares
       issued and outstanding 6,550,000 shares in 2001 and 2002                         6,550             6,550
       Additional paid-in capital                                                  20,905,197        20,905,197
       Retained earnings                                                            1,562,816         1,117,016
       Other comprehensive income (loss)                                                   --          (421,300)
                                                                                 ------------      ------------
                         Total shareholders' equity                                22,474,563        21,607,463
                                                                                 ------------      ------------

                         TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY              $ 36,719,674      $ 33,319,432
                                                                                 ============      ============
</TABLE>
                                      F-3
<PAGE>



                               GMX RESOURCES INC.
                      CONSOLIDATED STATEMENTS OF OPERATIONS
                     YEARS ENDED DECEMBER 31, 2001 AND 2002

<TABLE><CAPTION>
                                                            2001                  2002
                                                        ------------          ------------
<S>                                                     <C>                   <C>
REVENUE
      Oil and gas sales                                 $  5,898,003          $  5,970,792
      Interest income                                        198,933                 5,169
      Other income                                           355,363                12,381
                                                        ------------          ------------
           Total revenue                                   6,452,299             5,988,342
                                                        ------------          ------------

EXPENSES
      Lease operations                                     1,604,559             1,324,481
      Production and severance taxes                         338,637               382,826
      Depreciation, depletion and amortization             1,026,498             1,901,976
      Interest                                               359,118               510,472
      General and administrative                           1,855,736             2,577,388
                                                        ------------          ------------
           Total expenses                                  5,184,548             6,697,142
                                                        ------------          ------------

           Income before income taxes                      1,267,751              (708,800)

INCOME TAX EXPENSE (BENEFIT)                                 211,000              (263,000)
                                                        ------------          ------------

      Net income                                        $  1,056,751          $   (445,800)
                                                        ============          ============

      Net income applicable to common shares            $  1,056,751          $   (445,800)
                                                        ============          ============

      EARNINGS PER SHARE--BASIC                         $       0.21          $      (0.07)
                                                        ============          ============

      EARNINGS PER SHARE - DILUTED                      $       0.20          $      (0.07)
                                                        ============          ============

      WEIGHTED AVERAGE COMMON SHARES - BASIC               5,148,493             6,550,000
                                                        ============          ============

      WEIGHTED AVERAGE COMMON SHARES - DILUTED             5,179,693             6,550,000
                                                        ============          ============
</TABLE>

See accompanying notes to consolidated financial statements.


                                      F-4
<PAGE>

                               GMX RESOURCES INC.
            CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY
                     YEARS ENDED DECEMBER 31, 2001 AND 2002

<TABLE><CAPTION>
                                                                                          RETAINED      ACCUMULATED
                                                      COMMON STOCK          ADDITIONAL    EARNINGS         OTHER
                                                 ----------------------      PAID-IN    (ACCUMULATED)  COMPREHENSIVE      TOTAL
                                                   SHARES       AMOUNT       CAPITAL       DEFICIT)    INCOME (LOSS)      EQUITY
                                                 ----------    --------   ------------    ----------    -----------    ------------
<S>                                               <C>          <C>        <C>             <C>           <C>            <C>
BALANCE AT DECEMBER 31, 2000                      3,000,000       3,000      1,390,730       506,065                      1,899,795
Issuance of units                                 1,250,000       1,250      8,309,310            --             --       8,310,560
Issuance of shares                                2,300,000       2,300     11,205,157            --     11,207,457
Net income                                               --          --             --     1,056,751             --       1,056,751
Cumulative effect of change in accounting
  principle                                              --          --             --            --        (69,108)        (69,108)
Adjustment for derivative losses reclassified
  into oil and gas sales                                 --          --             --            --         64,189          64,189
Change in fair value of derivative instruments           --          --             --            --          4,919              --
                                                                                                                       ------------
Total comprehensive income (loss)                                                                                         1,056,751
                                                 ----------    --------   ------------    ----------    -----------    ------------
BALANCE AT DECEMBER 31, 2001                      6,550,000    $  6,550   $ 20,905,197     1,562,816             --    $ 22,474,563
                                                 ==========    ========   ============    ==========    ===========    ============

Net income                                                                                  (445,800)            --        (445,800)
Adjustment for derivative losses                         --          --             --            --         423,865        423,865
reclassified into oil and gas sales
Change in fair value of derivative
instruments                                              --          --             --            --       (845,165)       (845,165)
                                                                                                                       ------------
Total comprehensive income (loss)                        --          --             --      (445,800)      (421,300)       (867,100)
                                                 ----------    --------   ------------    ----------    -----------    ------------
BALANCE AT DECEMBER 31, 2002                      6,550,000    $  6,550   $ 20,905,197     1,117,016       (421,300)   $ 21,607,463
                                                 ==========    ========   ============    ==========    ===========    ============
</TABLE>






See accompanying notes to consolidated financial statements.

                                      F-5
<PAGE>

                               GMX RESOURCES INC.
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                     YEARS ENDED DECEMBER 31, 2001 AND 2002

<TABLE><CAPTION>
                                                                              2001                 2002
                                                                          ------------         ------------
<S>                                                                       <C>                  <C>
CASH FLOWS DUE TO OPERATING ACTIVITIES
      Net income (loss)                                                   $  1,056,751         $   (445,800)
      Adjustments to reconcile net income (loss) to
           net cash provided by (used in) operating activities:
               Depreciation, depletion, and amortization                     1,026,498            1,901,976

               Deferred income tax expense (benefit)                           211,000             (263,000)

               Gain on sale of other property and equipment                       (319)              (3,775)

               Gain on sale of investments                                          --               (3,714)
               Gain from demutualization of insurance company                  (74,124)                  --
               Decrease (increase) in:
                    Accounts receivable                                       (248,433)             744,636
                    Inventory and prepaid expenses                            (162,202)              19,874
                    Other assets                                               (14,024)              13,605
               Increase (decrease) in:
                    Accounts payable                                         6,267,630           (4,454,155)
                    Accrued expenses and other liabilities                     244,970             (123,934)
                    Revenue distributions payable                             (291,597)              66,648
                                                                          ------------         ------------

                         Net cash provided by (used in) operating
                         activities                                          8,016,600           (2,547,639)
                                                                          ------------         ------------

CASH FLOWS DUE TO INVESTING ACTIVITIES
      Additions to oil and gas properties                                  (24,385,466)          (3,014,288)
      Additions to property and equipment                                   (2,575,096)             (45,882)
      Proceeds from sale of other property and equipment                        15,953                5,000
      Proceeds from sale of investments                                             --               77,838
      Proceeds from sale of oil and gas properties                             243,824            4,245,163
                                                                          ------------         ------------
                         Net cash provided by (used in) investing
                         activities                                        (26,700,785)           1,267,831
                                                                          ------------         ------------

CASH FLOWS DUE TO FINANCING ACTIVITIES
      Proceeds from borrowings                                               1,765,000            5,898,000
      Payments of debt issuance costs                                          (22,500)                  --
      Payments on debt                                                      (3,058,864)          (4,078,000)
      Issuance of equity                                                    19,974,231                   --
                                                                          ------------         ------------
                         Net cash provided by (used in) financing
                         activities                                         18,657,867            1,820,000
                                                                          ------------         ------------

Net increase (decrease) in cash                                                (26,318)             540,192

CASH AT BEGINNING OF YEAR                                                       30,043                3,725
                                                                          ------------         ------------

CASH AT END OF YEAR                                                       $      3,725         $    543,917
                                                                          ============         ============


CASH PAID FOR INTEREST                                                    $    474,444         $    510,472
                                                                          ============         ============
</TABLE>
See accompanying notes to consolidated financial statements.

                                      F-6
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

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 Oklahoma, Kansas, 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 cost.

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 which GMX also
owns an interest in excess of related costs incurred are accounted for as
reductions of capitalized costs of oil and gas properties.

The sale of the Company's Kansas properties in September 2002 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.

Proved crude oil and natural gas properties and other long-lived assets are
periodically assessed to determine if circumstances indicate that the carrying
amount of an asset may not be recoverable. SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived

                                      F-7
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

Assets," was issued in August 2001. This statement addresses financial
accounting and reporting for the impairment or long-lived assets. This statement
supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for long-Lived Assets to Be Disposed Of." 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. The Company adopted the statement January 1, 2002 with no material
impact on the Company's results of operations or financial position.

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, 2002.

CAPITALIZED INTEREST: Interest of $64,410 and $59,195 was capitalized related to
the unproved properties that were not being currently depreciated, depleted, or
amortized and on which exploration activities were in progress in 2001 and 2002,
respectively.

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

                                      F-8
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

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.

The Company adopted the provisions of Statement of Financial Accounting
Standards (SFAS) 133, as amended, in the first quarter of the year ending
December 31, 2001. In accordance with the transition provisions of SFAS 133, the
Company recorded a net-of-tax cumulative-effect-type adjustment of approximately
$69,000 in accumulated other comprehensive loss to recognize at fair value all
derivatives that are designated as cash-flow hedging financial instruments.

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 and oil and gas reserve quantities.

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 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. See note I for the fair value of
the oil and natural gas price swap agreements.

NET EARNINGS PER COMMON SHARE: Basic earnings per share is computed by dividing
income available to common shareholders by the weighted average number of common
shares outstanding for the period. For 2001, diluted earnings per share reflect
the potential dilution that could occur if the Company's stock options were
exercised. The weighted average dilutive shares included in the 2001 period were
31,200. For 2002, the Company incurred a loss and as a result the effect of
stock options was antidilutive. There were no other dilutive instruments
outstanding in 2001 or 2002.

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

                                      F-9
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

123, GMX has elected to continue to apply the intrinsic value based method of
accounting described above, and has adopted the disclosure requirements of
Statement 123 which are included in note F.

Stock option activity for the year ended December 31, 2002 is as follows:

                                                              WEIGHTED
                                                               AVERAGE
                                            NUMBER OF         EXERCISE
                                             SHARES             PRICE
                                            ---------         ---------
     Balance as of December 31, 2000               --         $      --

         Granted                              170,000              5.72

         Exercised                                 --                --

         Forfeited                            (20,000)             6.26

         Expired                                   --                --
                                            ---------         ---------
     Balance as of December 31, 2001          150,000         $    5.72
          Granted                              13,000              3.50
          Exercised                                --                --
          Forfeited                            23,000              4.42
          Expired                                  --                --
                                            ---------         ---------
     Balance as of December 31, 2002          140,000         $    5.65
                                            ---------         ---------

At December 31, 2002, the range of exercise prices and weighted-average
remaining contractual life of outstanding options was $3.50 to $8.00 and 10
years, respectively.

At December 31, 2002, the number of options exercisable was 140,000 and the
weighted-average exercise price of those options was $5.65.

The Company applied APB Opinion No. 25. in accounting for its plan and
accordingly, no compensation cost has been recognized for its stock option 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.

                                                         2001        2002
                                                     -----------   ---------
     Net (loss) earnings as reported                 $ 1,056,751   $(445,800)

     Deduct:  Stock-based compensation, net of tax      (137,823)   (208,387)
                                                     -----------   ---------
     Pro forma                                           918,928    (654,187)
                                                     ===========   =========

For 2001, fair value was determined using the Black-Scholes option pricing model
with the following assumptions: expected dividend yield of 0%, risk-free
interest rate of 4.46%, expected volatility of 14.72%, and an expected term of
10 years.

                                      F-10
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

For 2002, 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 1.73%, expected volatility of 1.31%, and an expected term of 10
years.

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

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

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, 2002 and 2001.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS: In July 2001, the Financial
Accounting Standards Board issued SFAS 143, "Accounting for Asset Retirement
Obligations." SFAS 143 requires entities to record the fair value of a liability
for an asset retirement obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset.
SFAS 143 is effective for fiscal years beginning after June 15, 2002. The
Company has not calculated the impact of this statement on its reported results.

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No.
4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections,
that, among other things, rescinded SFAS No. 4, Reporting Gains and Losses from
Extinguishment of Debt. With the rescission of SFAS No. 4, the early
extinguishment of debt generally will no longer be classified as an
extraordinary item for financial statement presentation purposes. The provision
is effective for fiscal years beginning after May 15, 2002. The Company does not
anticipate that the adoption of SFAS No. 145 will have a material effect on its
financial position or results of operations.

In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with
Exit or Disposal Activities, which replaces Emerging Issues Task Force Issue No.
94-3, Liability Recognition for Certain Employee Termination Benefits and Other
Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).
The new standard required companies to recognize costs associated with exit or
disposal activities when they are incurred rather than at the date of a
commitment to an exit or disposal plan. The statement is to be applied
prospectively to exit or disposal activities initiated after December 31, 2002.
The Company does not anticipate that the adoption of SFAS No. 146 will have a
material effect on its financial position or results of operations.

                                      F-11
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based
Compensation - Transition and Disclosure, which amended SFAS No. 123, Accounting
for Stock-Based Compensation. The new standard provides alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. Additionally, the statement amends the
disclosure requirements of SFAS No. 123 to require prominent disclosures in the
annual and interim financial statements about the method of accounting for
stock-based employee compensation and the effect of the method used in reported
results. This statement is effective for financial statements for fiscal years
ending after December 15, 2002. In compliance with SFAS No. 148, the Company has
elected to continue to follow the intrinsic value method in accounting for its
stock-based employee compensation arrangement as defined by APB No. 25.

In November 2002, the FASB issued Interpretation No. 45 (FIN 45), Guarantor's
Accounting and Disclosure Requirement for Guarantees, Including Indirect
Guarantees of Indebtedness of Others. For a guarantee subject to FASB
Interpretation No. 45, a guarantor is required to measure and recognize the fair
value of the guarantee liability at inception. For many guarantees, fair value
will likely be determined using the expected present value method described in
FASB Concepts Statement 7, Using Cash Flow Information and Present Value in
Accounting Measurements. In addition, FIN 45 provides new disclosure
requirements. The disclosure requirements of FIN 45 were effective for the
Company as of December 31, 2002. The measurement and liability recognition
provisions are applied prospectively to guarantees or modifications after
December 31, 2002. The Company anticipates that FIN 45 will not have a material
impact on the Company's financial statements.

In January 2003, the FASB issued Interpretation No. 46, Consolidation of
Variable Interest Entities (FIN 46). Subject to certain criteria defined in the
Interpretation, FIN 46 will require consolidation by business enterprises of
variable interest entities if the enterprise has a variable interest that will
absorb the majority of the entity's expected losses, receives a majority of its
expected returns, or both. The provisions of FIN 46 are effective immediately
for interests acquired in variable interest entities after January 31, 2003, and
at the beginning of the first interim or annual period beginning after June 15,
2003, for interests acquired in variable interest entities before February 1,
2003 (for the Company in the third quarter of 2003). The Company anticipates
that FIN 46 will not have a material impact on the Company's financial
statements.







                                      F-12
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

NOTE B--PROPERTY AND EQUIPMENT

Property and equipment included the following:

<TABLE><CAPTION>
                                                                                     DECEMBER 31,
                                                                          ---------------------------------
                                                                              2001                 2002
                                                                          ------------         ------------
<S>                                                                  <C>                  <C>
     Oil and gas properties:
        Subject to amortization                                           $ 32,872,557         $ 31,710,171
        Not subject to amortization:
          Acquired in 2002                                                          --               76,829
           Acquired in 2001                                                  1,000,406              853,258
           Acquired in 2000                                                     62,158               93,195
           Acquired in 1999                                                     36,943                   --
           Acquired in 1998                                                    141,205              148,940
        Accumulated depreciation, depletion, and amortization               (1,964,654)          (3,522,584)
                                                                          ------------         ------------
            Net oil and gas properties                                      32,148,615           29,359,309
                                                                          ------------         ------------
     Other property and equipment                                            3,159,963            3,200,345
     Less accumulated depreciation                                            (317,302)            (656,572)
                                                                          ------------         ------------

            Net other property and equipment                                 2,842,661            2,543,773
                                                                          ------------         ------------
              Property and equipment, net of accumulated
                 Depreciation, depletion, and amortization                $ 34,991,276         $ 31,903,082
                                                                          ============         ============
</TABLE>

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

<TABLE><CAPTION>
                                                                                FOR THE YEAR ENDED
                                                                                    DECEMBER 31,
                                                                          ---------------------------------
                                                                              2001                 2002
                                                                          ------------         ------------
<S>                                                                       <C>                  <C>
     Depreciation, depletion, and amortization of oil
        and gas properties                                                $    855,716         $  1,557,930
     Depreciation of other property and equipment                              170,782              344,046
                                                                          ------------         ------------

                Total                                                     $  1,026,498         $  1,901,976
                                                                          ============         ============
</TABLE>

NOTE C--LONG-TERM DEBT

<TABLE><CAPTION>
                                                                                     DECEMBER 31,
                                                                          ---------------------------------
                                                                              2001                 2002
                                                                          ------------         ------------
<S>                                                                       <C>                  <C>
     Note  payable  to  bank,  maturity  date of May 1, 2003,             $  6,280,000         $  8,100,000
     bearing a variable  interest  rate (4.75% and 5.25% as of
     December 31, 2001 and 2002, respectively)  collateralized
     by producing oil and gas properties
                                                                          ------------         ------------
                                                                             6,280,000            8,100,000
     Current portion                                                        (6,280,000)          (8,100,000)
                                                                          ------------         ------------
                                                                          $         --         $         --
                                                                          ============         ============
</TABLE>
                                      F-13
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

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 plus 1%. 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 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. Beginning August 1,
2002, and continuing until the next Borrowing Base determination (September 1,
2002), monthly commitment reductions were $172,000 plus any positive difference
between the $172,000 and 80% of "Net Cash Flow" (net income before income taxes
plus non-cash expenses) for the second preceding month. The scheduled September
1, 2002 Borrowing Base determination was not made. At December 31, 2002, the
Company had borrowed $8,100, 000 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. The credit
facility matures on May 1, 2003.

As of December 31, 2002, the Company was not in compliance with the adjusted
current ratio or debt service coverage covenants included in the Credit
Facility. The lender has not waived the noncompliance items. The noncompliance
creates a technical default under the terms of the 2000 Credit Facility,
although the lender has not demanded immediate payment. As of March 1, 2003, the
Company's Borrowing Base has been redetermined by the bank to be $5,846,000. At
April 11, 2003, the Company did not have the resources available to pay the
credit facility at the May 1 maturity. As a result of the technical default and
the May 1, 2003 due date, the borrowings outstanding under the facility have
been reflected as current in the accompanying consolidated balance sheet.

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

At December 31, 2002, the Company had the following carryforwards available to
reduce future income taxes:

                                      F-14
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

         Federal                                    $  22,684,000
         States                                        11,526,000
         Statutory depletion                            1,875,000

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, 2002, the Company's deferred tax liability of $8,060,000 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 $8,350,000 was primarily the result of the
Company's net operating loss and statutory depletion carryforwards. As of
December 31, 2002, the Company recognized a valuation allowance of $290,000.
Management of the Company determined that based upon current taxable income and
financial conditions that it is not more likely than not that the Company will
be able to utilize all of its net operating loss carryforwards prior to their
expiration.

As of December 31, 2001, the Company's deferred tax liability of $8,206,000 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 $7,943,000 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:

                                               FOR THE YEAR ENDED
                                                  DECEMBER 31,
                                       ---------------------------------
                                           2001                 2002
                                       ------------         ------------
     U.S. statutory tax rate                     34%                  34%
     Statutory depletion                        (16)                 (34)
     Change in valuation allowance               --                   41
     Other                                       (1)                  (4)
                                       ------------         ------------
     Effective income tax rate                   17%                  37
                                       ============         ============

NOTE E--COMMITMENTS AND CONTINGENCIES

On December 13, 2001, we filed a lawsuit in the United States District Court for
the Western District of Oklahoma against Nabors Drilling USA, alleging that
Nabors made misrepresentations intended to induce GMX into entering into
drilling contracts as well as alleging that Nabors breached those contracts by
providing substandard drilling services. We terminated the drilling contracts
and were seeking damages in an amount representing specified excess cost and
loss of profits occasioned by Nabors' acts, plus attorneys' fees. A counterclaim

                                      F-15
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

was filed on January 31, 2002 by Nabors claiming that we breached the drilling
contracts by failing and/or refusing to pay the full amount of Nabors'
outstanding invoices and prematurely terminating the drilling contracts. Nabors
sought damages, consisting of $1.8 million in unpaid invoices, plus contract
termination fees, interest and attorneys' fees. During 2002, the Company paid
the outstanding invoices.

On December 20, 2002, the Company received a jury verdict in its favor against
Nabors Drilling USA, LP after a five day trial. As a result of the jury verdict,
the Company has no liability to Nabors and its claim for approximately $10
million in contract termination damages.

On March 3, 2003, Nabors Drilling USA, LP filed a new notice of appeal of the
unanimous jury verdict in GMX's favor rendered December 23, 2002 in its lawsuit
against Nabors in the United States District Court for the Western District of
Oklahoma. Nabors is appealing the verdict which found that the Company had no
liability to Nabors on its claim for approximately $10 million in contract
termination damages. The appeal process is likely to take more than 12 months
and if Nabors is successful, would probably result in a requirement for a new
trial. Nabors had previously been denied a new trial by the U.S. District Court
for the Western District of Oklahoma.

Based upon the prior jury verdict and prior denials of appeals, the Company does
not believe that a material loss is probable as of Decemner 31, 2002.

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, 2001.

Year Ending December 31:

          2003                                              $     100,673
          2004                                                     16,870
                                                            -------------
                Total                                       $     117,543
                                                            =============

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

          2001                                              $      82,739
          2002                                                     97,298

                                      F-16
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

NOTE F--SHAREHOLDERS' EQUITY

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

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

The board of directors may amend or terminate the Option Plan at any time,
except that no amendment will become effective without the approval of the
shareholders except to the extent such approval may be required by applicable
law or by the rules of any securities exchange upon which the Company shares are
admitted to listed trading. The Option Plan will terminate in 2010, except with
respect to awards then outstanding. No options were outstanding at December 31,
2000.

On February 12, 2001, the Company sold 1,250,000 units at a price of $8 per unit
and received approximately $8,550,000 in proceeds, net of commissions and
offering expenses. The units consisted of 1,250,000 shares of common stock,
1,250,000 class A warrants, and 1,250,000 class B warrants. The class A warrants
allow holders to purchase common shares of the Company for $9.00 per share prior
to March 12, 2002 and $12.00 per share thereafter. The class B warrants allow
holders to purchase common shares of the Company for $10.00 per share. The class
A warrants expire on February 12, 2006 and the class B warrants expire on
February 12, 2003. The Company used a portion of the proceeds of the offering to
repay $427,500 of loans from shareholders.

On July 17, 2001 and July 25, 2001, GMX sold 2,000,000 and 300,000 common
shares, respectively, at a price of $5.50 per share. Proceeds to GMX, net of
underwriters' fees and other expenses, were $11,285,544. GMX has also granted
the underwriters five-year warrants to purchase up to 200,000 shares for $6.60
per common share.

                                      F-17
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

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, 2001 and 2002 were as follows:

                                                         2001          2002
                                                         ----          ----
     Teppco Crude                                        28.7%         95.2%
     Koch Gateway Pipeline                               47.9%           --
     CrossTex Energy Services, Inc.                        --          77.3%

NOTE H--DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

During 2001, the Company utilized swap arrangements to hedge a portion of its
exposure to price volatility from producing natural gas. Each swap arrangement
established a price above which the Company paid the counterparty and below
which the Company was paid. Results from commodity hedging transactions are
reflected in gas sales. Payments by the Company in 2001 totaled $179,865.

The Company has entered into natural gas price swaps that initiated in March
2002 and will expire in February 2003. These agreements relate to 50,000 and
40,000 mmbtu whereby the Company will receive a fixed price of $2.66 and $2.67
per mmbtu, respectively and pay the counterparty an index price. Payments by the
Company in 2002 totaled $652,100.

The fair value of the financial instrument as of December 31, 2002 was a
liability of approximately $421,300. There were no outstanding financial
instruments as of December 31, 2001.

As of January 1, 2001, GMX adopted the provisions of Statement of Financial
Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and
Certain Hedging Activities" and SFAS No. 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities, an Amendment of SFAS No 133." SFAS
No. 133 and SFAS No. 138 require that all derivative instruments be recorded on
the balance sheet at their respective fair values. In accordance with the
transition provisions of SFAS No. 133, GMX recorded a net-of-tax
cumulative-effect-type adjustment of a $69,108 loss in accumulated other
comprehensive loss.

GMX's 2000 derivatives qualified for hedge accounting treatment that is
considered a "cash flow" hedge. GMX designates its cash flow hedge derivatives
as such on the date the derivative contract is entered into.

                                      F-18
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

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

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

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

GMX does not hold or issue derivative instruments for trading purposes. All of
GMX's commodity price financial swaps in place at January 1, 2002 were
designated as cash flow hedges. Changes in the fair value of these derivatives
were reported in "Accumulated other comprehensive income." These amounts were
reclassified to oil and gas sales when the forecasted transaction took place.
The 2002 derivative instruments did not qualify for hedge accounting. As a
result changes in fair value were reflected in the 2001 consolidated statements
of operations.

NOTE I--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-19
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

NOTE J--OIL AND GAS OPERATIONS

Capitalized costs related to the Company's oil and gas producing activities as
of December 31, 2001 and 2002 are:

                                                      2001             2002
                                                  ------------     ------------
     Unproved properties                          $  1,240,712     $  1,171,722
     Producing properties                           32,872,557       31,710,171
                                                  ------------     ------------
                                                    34,113,269       32,881,893
     Less accumulated depreciation, depletion,
        and amortization                            (1,964,654)      (3,522,584)
                                                  ------------     ------------
                Net capitalized costs             $ 32,148,615     $ 29,359,309
                                                  ============     ============

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 2001 and 2002 are as follows:

                                                      2001             2002
                                                  ------------     ------------
     Property acquisition costs - proved          $  2,488,614     $    120,157
     Property acquisition costs - unproved           2,382,548           84,672
     Development costs                              19,270,480        2,812,876
                                                  ------------     ------------
                                                  $ 24,141,642     $  3,017,705
                                                  ============     ============

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 2001 and 2002 include revenues and
expenses associated directly with oil and gas producing activities.

                                                      2001             2002
                                                  ------------     ------------
     Oil and gas sales                            $  5,898,004     $  5,970,792
     Production costs                                1,943,196        1,707,307
     Depreciation, depletion and amortization          855,716        1,557,930
     Income tax expense                                830,000          665,000
                                                  ------------     ------------
     Results of operations for oil and gas
          producing activities                    $  2,269,092     $  2,040,555
                                                  ============     ============

                                      F-20
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

NOTE K--SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED)

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

Proved oil and gas reserves represent the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are those expected to be recovered through
existing wells with existing equipment and operating methods. As of December 31,
2001 and 2002, all of the Company's oil and gas reserves were located in the
United States.

<TABLE><CAPTION>
                                                                 OIL                  GAS
                                                               (MBBLS)               (MMCF)
                                                             ------------         ------------
<S>                                                          <C>                  <C>
     DECEMBER 31, 2001
        Proved reserves, beginning of period                        3,858               49,070
        Extensions, discoveries, and other additions                1,217               30,178
        Production                                                    (81)              (1,294)
        Sale of reserves in-place                                     (70)                (119)
        Revisions of previous estimates                            (1,062)              (9,224)
                                                             ------------         ------------
        Proved reserves, end of period                              3,862               68,611
                                                             ============         ============
        Proved developed reserves:
            Beginning of period                                     1,410               15,352
                                                             ============         ============
            End of period                                           1,018               21,932
                                                             ============         ============
     DECEMBER 31, 2002
        Proved reserves, beginning of period                        3,862               68,611
        Extensions, discoveries, and other additions                   --                   --
        Production                                                    (70)              (1,639)
        Sale of reserves in-place                                  (1,218)              (2,263)
        Revisions of previous estimates                              (910)              (8,027)
                                                             ------------         ------------
        Proved reserves, end of period                              1,664              (56,682)
                                                             ============         ============
        Proved developed reserves:
            Beginning of period                                     1,018               15,352
                                                             ============         ============
            End of period                                             604               16,501
                                                             ============         ============
</TABLE>

Future cash inflows and future production and development costs are determined
by applying year-end prices and costs to the estimated quantities of oil and gas
to be produced. Estimates are

                                      F-21
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

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

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

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

<TABLE><CAPTION>
                                                         DECEMBER 31,         DECEMBER 31,
                                                             2001                 2002
                                                         ------------         ------------
                                                         (IN THOUSANDS)      (IN THOUSANDS)
<S>                                                      <C>                  <C>
     Future cash inflows                                 $    247,148         $    294,669
     Future production costs                                  (49,861)             (47,917)
     Future development costs                                 (41,609)             (39,518)
     Future income tax provisions                             (49,211)             (60,799)
                                                         ------------         ------------

          Net future cash inflows                             106,467              125,537
     Less effect of a 10% discount factor                     (57,939)             (71,225)
                                                         ------------         ------------
          Standardized measure of discounted future
              net cash flows                             $     48,528         $     54,312
                                                         ============         ============
</TABLE>

Oil and condensate prices were based on an equivalent base price of $28.98 per
barrel for benchmark posted West Texas Intermediate Crude Oil at closing on
December 31, 2002. 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 $28.85 per barrel. Natural gas prices were based on an equivalent base price
of $4.617 per million British thermal unit (mmbtu) for the composite Henry Hub
Spot Market benchmark price at closing on December 31, 2002. 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 $4.35 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-22
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2001 AND 2002

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

<TABLE><CAPTION>
                                                                     DECEMBER 31,         DECEMBER 31,
                                                                         2001                 2002
                                                                     ------------         ------------
<S>                                                                  <C>                  <C>
     Standardized measure, beginning of year                              186,281               48,524
     Sales of oil and gas, net of production costs                         (4,446)              (2,508)
     Net changes in prices and production costs                          (200,847)              51,708
     Extensions and discoveries, net of future development costs           22,465                   --
     Development costs that reduced future development costs                2,250                2,091
     Revisions of quantity estimates                                      (15,718)             (20,447)
     Sales of reserves in place                                              (579)             (15,192)
     Accretion of discount                                                 28,416                7,095
     Other                                                                (44,750)             (13,084)
     Net changes in income taxes                                           75,452               (3,875)
                                                                     ------------         ------------
     Standardized measure, end of year                                     48,524               54,312
                                                                     ============         ============
</TABLE>

NOTE L -- GOING CONCERN AND MANAGEMENT'S PLANS

As discussed in Note C, as of December 31, 2002, the Company was not in
compliance with two of its covenants included in its Credit Facility. Also, as
of March 1, 2003, amounts outstanding under the Credit Facility were in excess
of the redetermined Borrowing Base. Additionally, the Credit Facility matures on
May 1, 2003. The Company does not have the resources currently available to pay
the amounts outstanding under the Credit Facility. As a result of these factors
and the significant working capital deficit as of December 31, 2002, there
continues to be substantial doubt about the Company's ability to continue
operating as a going concern. The financial statements do not include any
adjustments relating to the recoverability and classification of asset carrying
values on the amount or classification of liabilities that might result if the
Company is unable to continue operating as a going concern.

The Company plans to continue to oppose legal proceedings related to Nabors. A
finding in the Company's favor against Nabors' appeal would reduce the Company's
exposure to amounts asserted as obligations by Nabors. See Note E.

The Company is actively pursuing additional debt and equity financings to
complement expected positive operating cash flow in order to reduce the
Company's past due accounts payable balance, repay or refinance its credit
facility and continue the Company's development program. The continuing
uncertainty with respect to the Nabors litigation described in Note E has had an
adverse affect on the Company's ability to raise capital. The Company may also
enter into development arrangements with other industry participants to fund the
development of the Company's proved undeveloped reserves. Such arrangements
would reduce or eliminate the Company's initial cash disbursements for
development. Such arrangements would also reduce the Company's future expected
operating cash flows due to the reduced interest ownership. There can be no
assurance that the Company will be able to enter into any of these financial
arrangements. As a result of the liquidity issues described above, the Company
has reduced its capital expenditures in the first quarter of 2003.


                                      F-23
<PAGE>


                                  EXHIBIT INDEX
                                  -------------

Exhibit No.                Description

10.3(c)         Third Amendment to Credit Agreement dated August 16, 2002
99.1            Certification of Chief Executive Officer Pursuant to 18
                U.S.C. Section 1350
99.2            Certification of Chief Financial Officer Pursuant to 18
                U.S.C. Section 1350