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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, 2001
                                      --------------------------------------
[ ]      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 of               (I.R.S. Employer Identification
         incorporation)                                        No.)

          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, Class B 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, 2001 was $6,452,299.

The aggregate market value of the voting and non-voting common equity (excluding
warrants) held by non-affiliates at March 26, 2002 was $4,114,460. This amount
was computed using closing price of the issuer's common stock on March 26, 2002
on the NASDAQ National Market.

As of March 26, 2002, 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 2002 Annual Meeting,
Part III.

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

<PAGE>

                              GMX RESOURCES INC.
                                 Form 10-KSB
                              Table of Contents
                                                                            Page
                                                                            ----

                                    PART I

   Item 1.    BUSINESS.........................................................1
              General..........................................................1
              2001 Equity Offerings............................................1
              Business Strategy................................................2
              Marketing........................................................3
              Regulation.......................................................4
              Gas Gathering....................................................6
              Competition......................................................6
              Drilling Contract................................................7
              Facilities.......................................................7
              Employees........................................................8
              Certain Technical Terms..........................................8

   Item 2.    PROPERTIES......................................................11
              Reserves........................................................15
              Costs Incurred and Acquisition and Drilling Results.............17
              Productive Well Summary.........................................18
              Productive Wells................................................19

   Item 3.    LEGAL PROCEEDINGS...............................................19

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

                                    PART II

   Item 5.    MARKET FOR REGISTRANT'S COMMON EQUITY AND
                 RELATED STOCKHOLDER MATTERS..................................20

   Item 6.    MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN
                 OF OPERATION.................................................21
              Selected Financial Data.........................................21
              Summary Operating and Reserve Data..............................23
              Critical Accounting Policies....................................24
              Results of Operations--Year Ended December 31, 2001
                 Compared to Year Ended December 31, 2000.....................25

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              Results of Operations for the Year Ended December 31,
                 2000 Compared to Year Ended December 31, 1999................27
              Capital Resources and Liquidity.................................28
              Cash Flow--Year Ended December 31, 2001 Compared to Year
                 Ended December 31, 2000......................................28
              Cash Flow--2000 Compared to 1999................................29
              Credit Facility.................................................29
              Working Capital.................................................30
              Shareholder Loans...............................................30
              Commitments and Capital Expenditures............................30
              Liquidity and Financing Considerations..........................31
              Price Risk Management...........................................31
              Impact of Recently Issued Accounting Standards Not Yet
                 Adopted......................................................32
              Forward-Looking Statements......................................33
              Risk Factors Related to GMX.....................................33
              Risks Related to the Oil and Gas Industry.......................36

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

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

                                   PART III

   Item 9.    DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND
                 CONTROL PERSONS; COMPLIANCE WITH SECTION 16(a)
                 OF THE EXCHANGE ACT..........................................41

   Item 10.   EXECUTIVE COMPENSATION..........................................41

   Item 11.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
                 OWNERSHIP AND MANAGEMENT.....................................42

   Item 12.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS..................42

   Item 13.   EXHIBITS AND REPORTS ON FORM 8-K................................42

                                      ii

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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, 2001, 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.

                                      1

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BUSINESS STRATEGY

         Our strategy is to create additional value from our existing 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 will also continue to seek
improvement in operating efficiencies, exploitation of existing recompletion and
work-over opportunities and will consider acquisitions of additional properties
when favorable opportunities are presented. We will implement these strategies
with 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 27 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 64
Bcfe of proved undeveloped reserves as of December 31, 2001. These projects
include 11 recompletion projects and 48 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, 2001 reserve report, the pre-tax present
value of the proved undeveloped reserves is $87 million with anticipated future
development costs of $40.9 million.

         Significant Inventory of Unproved Prospects. We have approximately 39
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. We are continuing to evaluate our acreage in Kansas and New Mexico
and we expect to generate additional drilling prospects. However, none of these
prospects have proved reserves assigned. Approximately 21,485 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 2001 was 73% gas and 27% oil.
Proved reserves as of December 31, 2001 are 75% gas and 25% 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.

                                      2

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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 included Teppco Crude and Koch Gateway PipeLine,
which accounted for 88.5% and 74.1% of oil and natural gas sales, respectively,
in 2001. We do not believe that the loss of any 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.

                                      3

<PAGE>

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. Persons
who are or

                                      4

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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.

                                      5

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

         Marketing and Transportation. 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, 2001, this gathering system consisted of approximately 34 miles of
gathering lines that collect gas from approximately 24 wells, which accounted
for approximately 89% and 65% of our gas production from this area in 2001 and
2000, 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

                                      6

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

         Recent increased oil and gas drilling activity in 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.

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 has drawn the full
$1,000,000 on the letters of credit and has counterclaimed for approximately
$9,000,000 alleged to be owed for an early termination fee and unpaid invoices.
See "Legal Proceedings."

FACILITIES

         As of December 31, 2001, we leased approximately 6,749 square feet in
Oklahoma City, Oklahoma for our corporate headquarters. The annual rental cost
is approximately $94,485.

                                      7

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EMPLOYEES

         As of December 31, 2001, we had 18 full-time employees of which four
are management and the balance are clerical or technical employees. We also use
five 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.

         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.

         EBITDA. EBITDA is defined as income (loss) before interest, income
taxes, depreciation, depletion and amortization. We believe that EBITDA is a
financial measure commonly used in the oil and gas industry, and we use it, and
expect our investors to use it, as an indicator of a

                                      8

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company's ability to service and incur debt and fund capital expenditures. One
of our debt covenants uses a measure similar to EBITDA. However, EBITDA should
not be considered in isolation or as a substitute for net income, cash flows
provided by operating activities or other data prepared in accordance with
accounting principles generally accepted in the United States of America, or as
a measure of a company's profitability or liquidity. EBITDA measures as
presented may not be comparable to other similarly titled measures of other
companies.

         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.

         MMBbls. Million barrels.

         MMBtu. Million Btus.

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         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 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

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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.

         Reserve Life. A measure of how long it will take to produce a quantity
of reserves, calculated by dividing estimated proved developed producing
reserves by production for the twelve-month period prior to the date of
determination (in gas equivalents).

         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.

ITEM 2.       PROPERTIES

         To date our activities have been conducted mainly in well known
productive basins in the United States in which our acquired properties are
located:

                                      11

<PAGE>

         . The Sabine Uplift in East Texas and Louisiana;
         . The Hugoton Basin in Western Kansas and Oklahoma;
         . The Sedgwick Basin in Central Kansas; and
         . The Tatum Basin in Southeast New Mexico.

         The following table sets forth certain information regarding our
activities in each of our principal areas as of December 31, 2001.

<TABLE>
<CAPTION>
                                                        Western             Southeast
                                         East Texas    Kansas and  Central     New
                                       and Louisiana    Oklahoma    Kansas    Mexico     Total
                                       -------------    --------    ------    ------     -----
<S>                                        <C>         <C>        <C>       <C>       <C>
Property Statistics:
Proved reserves (MMcfe) ...............       77,556      4,038      5,736    4,451     91,781
Percent of total proved reserves.......          85%         4%         6%       5%       100%
Gross producing wells .................           54         55         24        7        140
Net producing wells....................         41.1       21.3        8.3      5.6       76.6
Gross acreage .........................       21,458     10,899      3,556    2,077     37,990
Net acreage ...........................       19,065      3,823      2,300    1,888     27,076
Proved undeveloped reserves (MMcfe)           54,474      1,933      3,468    3,865     63,740
Estimated development costs ($000s)        $  37,308   $    502   $  1,589  $ 2,210   $ 41,609
Proved undeveloped locations ..........           39          2          4        3         48

Year ended December 31, 2001 results:
Production (net MMcfe).................        1,345        216        112      105      1,778
Average net daily production (Mcfe)....        3,685        592        307      288      4,872
</TABLE>

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

         Additional information related to our oil and gas activities is
included in Note J to the financial statements on Pages F-1 through F-25.

East Texas and Northwestern Louisiana

East Texas

         The East Texas properties are located in Harrison and Panola Counties,
Texas. These properties contain approximately 20,778 gross (18,602 net) acres
with rights covering the Travis Peak, Pettit, Glen Rose and Cotton Valley
formations. Our East Texas properties have 77.2 Bcfe of proved reserves or 84%
of our total proved reserves at December 31, 2001, of which 54.5 Bcfe is
classified as proved undeveloped.

         We have interests in 48 gross (38.7 net) producing wells in East Texas,
of which we operate 45. Average daily production net to our interest for 2001
was 3.1 Mcf of gas and 84 Bbls of oil. Production is primarily from the Betheny,
Blocker and Waskom Fields. The producing lives of these fields are generally 12
to 70 years. We have identified productive zones in the existing wells that are
currently behind pipe and thus are not currently producing. These zones can

                                      12

<PAGE>

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 54.5 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 2001 was 1,760 Mmcfe compared with production in 2000 of 1,158 Mmcfe, a
year-over-year increase of 52%. At production levels as of March 31, 2002, the
Company's annual production volume would be in excess of 2,062 Mmcfe net to the
Company's interest, with annual sales volumes, based on current prices of $3.30
per Mcf for natural gas and $25.85 per barrel of oil, of $7.2 million. GMX owns
a 100% working interest in each of the new East Texas wells. Based on these
results and the potential for further development, GMX initially plans to drill
eight wells in East Texas during 2002 subject to availability of capital
resources. The pace of future development of this property will depend on 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. We
are actively acquiring additional acreage in the vicinity of our existing
property to enhance the exploitation potential of these properties by adding
additional potential drilling locations. Over 4,551 additional acres were leased
in the East Texas Basin during 2001 contiguous to the Company's existing
property to further add to the more than 400 potential drilling locations
already in the GMX inventory.

         At December 31, 2001, Sproule Associates, Inc., our independent reserve
engineering firm, assigned a total of 14.4 Bcfe of proved reserves to the
completed East Texas wells and 54.5 Bcfe of proved undeveloped reserves to our
39 proved undeveloped locations in East Texas.

                                      13

<PAGE>

         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.

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, 2001. Average
daily production net to our interest for 2001 was 13 Bbls of oil and 19 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.

Western Kansas and Oklahoma Panhandle

         The Western Kansas areas are located in the Hugoton Embayment of Finney
and Scott Counties in Kansas. These areas combined consist of approximately
10,899 gross (3,823 net) acres. Our Western Kansas properties have 4,038 MMcfe
of proved reserves or 4% of our total proved reserves at December 31, 2001. The
Hugoton Embayment is one of the largest gas fields on the North American
Continent. We have a total of 55 gross (21.3 net) producing wells as of December
31, 2001. Substantially all of these wells penetrate multiple formations which
have additional development potential. Average daily production net to our
interest for 2001 was 215 Mcf of gas and 62 Bbls of oil. The producing
reservoirs in the Hugoton Embayment have low permeability, so their production
rates are generally modest while their productive lives are generally longer
than 20 years.

         Our producing properties are producing from various porosity intervals
of the Chase, Lansing, Kansas City, Marmaton and Mississippian formations at
depths from 2,500 to 4,600 feet. We have several producing units in this area.
One of the larger units is the Nunn Pool waterflood. In a waterflood, water is
pumped into the producing formation from one or more wells to force the oil to
migrate to the production wells. The Nunn Pool Field is producing from the
Mississippian and Marmaton formations. We are currently evaluating the
engineering plan to increase production from the Nunn Pool waterflood. In
Western Kansas, we have identified two locations with proved undeveloped
reserves of 1,933 MMcfe as of December 31, 2001. We are continuing to evaluate
these properties for further development potential.

                                      14

<PAGE>

         Two infield wells were drilled successfully and completed in the Nunn
Unit, Finney County, Kansas. One of the wells is currently producing crude oil
and the other has been converted into a salt-water injection well to improve the
production of previously existing wells in the Nunn Unit. Due to the
comparatively modest production of these wells, no further development of this
area is contemplated at this time.

Central Kansas

         The Central Kansas properties consist of approximately 3,556 gross
(2,300 net) acres located in Kingman, Sedgwick, Kiowa and Comanche Counties that
are part of the Sedgwick Basin. Proved reserves in Central Kansas represent 6%
of our total proved reserves at December 31, 2001. Average daily production net
to our interests for 2001 was 168 Mcf of gas and 23 Bbls of oil.

         We have 24 gross (8.3 net) producing wells producing from the
Mississippian formation, two of which are commingled in the Lansing Kansas City
formation. Our Unruh Unit is a water flood of the Marmaton Limestone formation
at a depth of approximately 4,600 feet. We have identified 4 locations with
proved undeveloped reserves of 3,458 MMcfe as of December 31, 2001 and are
continuing to review others.

Southeast New Mexico

         Our Southeast New Mexico properties are located in Lea and Roosevelt
counties and consist of approximately 2,077 gross (1,888 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 5% of our total proved reserves as of December 31, 2001.
Average daily production net to our interests for 2001 from our 7 gross (5.6
net) producing wells in this area was 63 Mcf of gas and 37 Bbls of oil.

         We have identified three locations with proved undeveloped reserves of
3,865 MMcfe as of December 31, 2001, which are planned for drilling after 2002
when we have completed planned drilling in East Texas and Kansas. If successful,
each well could increase net production by approximately 1,729 Bbls of oil per
day and 217 Mcf of gas per day. 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, 2001, Sproule Associates Inc. estimates our proved
reserves have increased to 92 Bcfe. An estimated 28 Bcfe is expected to be
produced from existing wells and

                                      15

<PAGE>

another 64 Bcfe or 69% 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, 2001, we
had interests in 140 producing wells, 130 of which we operate.

         No estimates of our proved reserves have been filed with or included in
reports to any federal authority or agency since the beginning of the last
fiscal year.

         The following table shows the estimated net quantities of our proved
reserves as of the dates indicated and the Estimated Future Net Revenues and
Present Values attributable to total proved reserves at such dates.

<TABLE>
<CAPTION>
                                                             Years Ended December 31,
                                                   -----------------------------------------
                                                       1999          2000           2001
                                                   -----------   ------------   ------------
<S>                                                   <C>          <C>            <C>
Proved Developed:
Gas (MMcf) ........................................     9,194        15,352         21,932
Oil (MBbls) .......................................     1,083         1,410          1,018
     Total (MMcfe).................................    15,692        23,811         28,040
Proved Undeveloped:
Gas (MMcf) ........................................    10,084        33,718         46,679
Oil (MBbls) .......................................       564         2,448          2,844
     Total (MMcfe).................................    13,468        48,406         63,740
Total Proved:
Gas (MMcf) ........................................    19,278        49,070         68,611
Oil (MBbls) .......................................     1,647         3,858          3,862
     Total (MMcfe).................................    29,160        72,218         91,781
Estimated Future Net Revenues /(1)/($000s).........   $50,052      $492,310       $155,678
Present Value/(1)/($000s) .........................   $30,523      $284,161       $ 70,952
</TABLE>

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

/(1)/  The prices used in calculating Estimated Future Net Revenues and the
       Present Value are determined using prices as of period end. Estimated
       Future Net Revenues and the Present Value give no effect to federal or
       state income taxes attributable to estimated future net revenues. The
       standardized measure of discounted future net cash flows as of 1999, 2000
       and 2001 was $22,903,000, $186,201,000 and $48,524,000, respectively.

         The significant increase in proved reserves from December 31, 2000 to
December 31, 2001 resulted from the drilling and completion of ten wells in the
Travis Peak, Pettit and Cotton Valley formations in East Texas which confirmed
the presence of additional undeveloped reserves in these formations as well as
additional geological and engineering evaluation of our property base.

                                      16

<PAGE>

         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, 2001 were $18.40 per
barrel for oil and $2.57 per Mcf for gas (prices used for December 31, 2000
reserve estimation were $26.42 per barrel and $9.90 per MMbtu), adjusted for
quality, contractual agreements, regional price variations and transportation
and marketing fees. These period end prices are not necessarily the prices we
expect to receive for our production but are required to be used for disclosure
purposes by the SEC. We estimate that if all other factors (including the
estimated quantities of economically recoverable reserves) were held constant, a
$1.00 per Bbl change in oil prices and a $.10 per Mcf change in gas prices from
those used in calculating the Present Value would change such Present Value by
$1,971,000 and $3,643,000 respectively, as of December 31, 2001.

         Sproule Associates, Inc., our independent reserve engineers, prepared
the estimates of proved reserves as of December 31, 2001 and 2000. Estimates of
proved reserves for December 31, 1999 were prepared by Jon Stromberg, an
independent petroleum engineer. In October 2000, Mr. Stromberg became our Vice
President--Operations.

         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.

<TABLE>
<CAPTION>
                                                                  Year ended December 31,
                                                    ----------------------------------------------------
                                                         1999                2000              2001
                                                    -------------       --------------     -------------
<S>                                                <C>                  <C>               <C>
Property acquisition costs:
   Proved.................................         $    514,212         $    359,753      $  2,382,548
   Unproved...............................              199,860              335,259         2,488,614

Development costs.........................              490,587            1,379,531        19,270,480
                                                    -------------        -------------     -------------
        Total.............................         $  1,204,659         $  2,074,543      $ 24,141,642
                                                    =============        =============     =============
</TABLE>

         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.

                                      17

<PAGE>

<TABLE>
<CAPTION>
                                                          Year Ended December 31,
                             --------------------------------------------------------------------------------
                                        1999                     2000                         2001
                             ------------------------- -------------------------- ---------------------------
<S>                              <C>          <C>           <C>         <C>             <C>           <C>
Development
wells:
 Gas....................          1           .8             1           1              10             10
 Oil....................          1           .8            --          --               1             .5
 Dry....................         --           --            --          --              --             --
   Total................     ----------- ------------   ----------- ------------   ------------ -------------
                                   2          1.6            1           1              11            10.5
                             =========== ============   =========== ============   ============ =============
</TABLE>

         The following table shows our developed and undeveloped oil and gas
lease and mineral acreage as of December 31, 2001. Excluded is acreage in which
our interest is limited to royalty, overriding royalty and other similar
interests.

<TABLE>
<CAPTION>
                                                             Developed               Undeveloped
                                                      ------------------------ ------------------------
Location                                                 Gross         Net        Gross        Net
--------                                              ------------ ----------- ------------ -----------
<S>                                                       <C>         <C>           <C>        <C>
                                                                      13,791
East Texas and Louisiana.......................           14,640           1        6,818      5,274
Western Kansas and Oklahoma....................           10,899       3,823           --         --
Central Kansas.................................            3,556       2,300           --         --
Southeast New Mexico...........................            1,760       1,571          317        317
                                                      ------------ ----------- ------------ -----------
      Total....................................           30,855      21,485        7,135      5,591
                                                      ============ =========== ============ ===========
</TABLE>

     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 and division orders 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, 2001. 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.

                                      18

<PAGE>

PRODUCTIVE WELLS

                                                             Productive Wells
                                                           ---------------------
Type of Well                                                 Gross        Net
------------                                                 -----        ---
Gas....................................................       60         38.9
Oil....................................................       80         37.7
                                                           ----------  ---------
      Total............................................      140         76.6
                                                           ==========  =========

ITEM 3.       LEGAL PROCEEDINGS

      On March 1, 2001, Larry Miller and certain other parties filed an action
in the United States District Court for the Eastern District of Texas, Marshall
Division, against us and our President, Ken L. Kenworthy, Jr., alleging fraud
and breach of implied contract and seeking damages relating to a claimed
interest in an oil and gas well we drilled in Harrison County, Texas in 2000.
The Plaintiff claims we permitted Downs No. 1 Well to cease producing and the
relevant leases to expire and subsequently drilled another well in lieu of
reworking or redrilling the well. The Plaintiffs claim they were entitled to an
interest in the well and seek actual damages of $750,000, unspecified punitive
damages and attorneys fees. We have denied these allegations and asserted that
the old leases expired due to lack of production after numerous attempts were
made to restore the well problem. We have also claimed that we purchased the
leases in question out of the PPMI/ORMI bankruptcy proceeding free and clear of
all unrecorded claims. In a related proceeding, on October 9, 2001, we filed a
motion to reopen the bankruptcy proceeding and filed a notice of appeal on the
denial of such motion on January 22, 2002. We moved to reopen the first
proceeding in order to institute adversary proceedings seeking orders declaring
that we purchased the oil and gas property that is at issue in this lawsuit free
and clear of the interest claimed by the plaintiffs. We intend to vigorously
defend this action and do not believe it will have any material adverse effect
on our financial condition or results of operations.

      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 contracts and are
seeking damages in an amount representing specified excess cost and loss of
profits occasioned by Nabors' acts, plus attorneys' fees. A counterclaim 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
seeks damages of $8.9 million, consisting of $1.8 million in unpaid invoices and
$7.1 million for contract termination fees, plus interest and attorneys' fees.

      In February 2002, Nabors filed materialmen's liens against seven wells
asserting claims for amounts due for drilling services on these wells in the
aggregate amount of $1.8 million and demanded payment by March 21, 2002. The
Company intends to dispute these claims based on

                                      19

<PAGE>

its position that Nabors' draw on a $1 million letter of credit to secure
payment should have been applied to the unpaid invoices and that some of the
amounts are not otherwise properly owing. Nabors has threatened to foreclose
its lien if it is not paid, which if successful, could result in the Company
losing all or a portion of its interest in these wells.

     This action is still in the preliminary stages. We intend to vigorously
prosecute and defend this action, but the ultimate outcome is not determinable.
If Nabors prevails in this litigation, it could have a material adverse effect
on our financial condition, results of operations and prospects.

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

     There were no matters submitted during the fourth quarter of 2001 to a vote
of the shareholders.

                                    PART II

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

     Until February 12, 2001, we had no publicly traded securities. In our
initial public offering on February 12, 2001, we listed our units on the NASDAQ
SmallCap Market under the symbol "GMXRU." On March 15, 2001, the units ceased
trading as such and our common stock, Class A warrants and Class B warrants
began trading separately. Effective June 22, 2001, we began trading on the
NASDAQ National Market. The high and low bid prices for our securities as listed
on the NASDAQ SmallCap Market or the NASDAQ National Market as applicable during
the periods described below were as follows:

                                               High              Low
                                               ----              ---
February 12, 2001 to March 14, 2001
-----------------------------------
Units..................................    $ 8.625            $ 7.125
March 15, 2001 to March 31, 2001
--------------------------------
Common Stock...........................    $ 5.813            $ 3.375
Class A warrants.......................      1.625              1.063
Class B warrants.......................      1.625              1.000
April 1, 2001 to June 22, 2001
------------------------------
Common Stock...........................    $12.600            $ 5.250
Class A warrants.......................      4.400              1.313
Class B warrants.......................      4.350              1.200
June 22, 2001 to June 30, 2001
------------------------------
Common Stock...........................    $12.100            $10.250
Class A warrants.......................      4.350              3.180
Class B warrants.......................      4.000              2.900

                                      20

<PAGE>

July 1, 2001 to September 30, 2001
----------------------------------
Common Stock...........................    $10.700            $ 4.000
Class A warrants.......................      3.350              1.150
Class B warrants.......................      3.000              0.940
October 1, 2001 to December 31, 2001
------------------------------------
Common Stock...........................    $ 6.250            $ 3.780
Class A warrants.......................      2.150              0.700
Class B warrants.......................      1.540              0.510

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

     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. Each Class B warrant
entitles the holder to purchase one share of common stock for $10.00 per share
until February 12, 2003.

     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.

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.

                                      21

<PAGE>

<TABLE>
<CAPTION>
                                                                           Years Ended December 31,
                                                      ---------------------------------------------------------------------
                                                           1998/(1)/         1999             2000              2001
                                                      ---------------   --------------   --------------   -----------------
<S>                                                  <C>               <C>              <C>              <C>
Statement of Operations Data:
Oil and gas sales..................................  $     1,794,513   $    2,122,770   $    4,153,934   $       5,898,003
Interest and other income..........................           33,404           38,915           37,378             554,296
                                                      ---------------   --------------   --------------   -----------------
   Total revenues..................................        1,827,917        2,161,685        4,191,312           6,452,299
                                                      ---------------   --------------   --------------   -----------------
Lease operations...................................          924,246          960,489        1,207,095           1,604,559
Production and severance taxes.....................          121,705          114,294          260,064             338,637
General and administrative.........................          226,313          368,824          578,641           1,855,736
Depreciation, depletion and amortization...........          426,562          424,509          420,488           1,026,498
Interest...........................................          426,709          498,199          664,713             359,118
                                                      ---------------   --------------   --------------   -----------------
   Total expenses..................................  $     2,125,535   $    2,366,315   $    3,131,001   $       5,184,548
                                                      ---------------   --------------   --------------   -----------------
Income (loss) before income taxes..................         (297,618)        (204,630)       1,060,311           1,267,751
Income taxes.......................................               --               --           52,000             211,000
                                                      ---------------   --------------   --------------   -----------------
Net income (loss)..................................  $      (297,618)  $     (204,630)  $    1,008,311   $       1,056,751
                                                      ===============   ==============   ==============   =================
Net income (loss) applicable to common shares......  $      (478,368)  $     (373,193)  $      875,810   $       1,056,751
                                                      ===============   ==============   ==============   =================
Net income (loss) per share - basic ...............  $          (.22)  $         (.23)  $          .48   $             .21
                                                      ===============   ==============   ==============   =================
Net income (loss) per share - diluted .............  $          (.22)  $         (.23)  $          .29   $             .20
                                                      ===============   ==============   ==============   =================
Weighted average common shares - basic.............        2,176,500        1,632,375        1,822,926           5,148,493
                                                      ===============   ==============   ==============   =================
Weighted average common shares - diluted...........        2,176,500        1,632,375        3,469,326           5,179,693
                                                      ===============   ==============   ==============   =================
Statement of Cash Flows Data:
Net cash provided by operating activities..........  $       197,231   $      618,759   $    1,394,168   $       8,016,600
Net cash used in investing activities..............       (6,720,450)        (685,060)      (2,177,335)        (26,700,785)
Net cash provided by financing activities..........        6,633,001          491,724          277,997          18,657,867

Balance Sheet Data (at end of period):
Oil and gas properties, net........................  $     6,870,847   $    7,140,790   $    8,862,690   $      32,148,615
Total assets.......................................        8,003,667        8,973,163       10,970,282          36,719,674
Long-term debt, including current portion..........        5,677,348        6,181,813        7,573,864           6,280,000
Shareholders' equity...............................        1,702,382        1,117,483        1,899,793          22,474,563

Other Data:
EBITDA/(2)/........................................  $       555,653   $      718,078   $    2,145,512   $       2,653,367
</TABLE>

-------------------------
/(1)/The Company began operations on January 23, 1998. As such, the 1998 period
     reflects activity from inception date to December 31, 1998.

/(2)/EBITDA is defined as income (loss) before interest, income taxes,
     depreciation, depletion and amortization costs. We believe that EBITDA is a
     financial measure commonly used in the oil and gas industry, and we use it,
     and expect investors to use it, as an indicator of a company's ability to
     service and incur debt or fund capital expenditures. One of our debt
     covenants uses a measure similar to EBITDA. However, EBITDA should not be
     considered in isolation or as a substitute for net income, cash flows
     provided by operating activities or other data prepared in accordance with
     accounting principles generally accepted in the United States of America,
     or as a measure of a company's profitability or liquidity. EBITDA measures
     as presented may not be comparable to other similarly titled measures of
     other companies.

                                      22

<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,
                                                          -----------------------------------------------------
                                                             1998          1999          2000           2001
                                                          ----------    ---------     ----------    -----------
<S>                                                      <C>           <C>           <C>          <C>
Production:
Oil production (MBbls)..................................       75            71           75            81
Natural gas production (MMcf)...........................      442           443          719         1,294
Equivalent production (MMcfe)...........................      892           869         1158         1,778

Average Sales Price:
Oil price (per Bbl)..................................... $  12.67      $  16.73      $ 21.33/(1)/ $  24.86/(1)/
Natural gas price (per Mcf).............................     1.91          2.09         3.57          3.01/(1)/
                                                          ----------    ---------     ----------    -----------

Average sales price (per Mcfe).......................... $   2.01      $   2.43      $  3.59      $   3.33

Operating and Overhead Costs (per Mcfe):
Lease operating expenses................................     1.03      $   1.11      $  1.04      $    .90
Production and severance taxes..........................      .14           .13          .36           .19
General and administrative..............................      .25           .42          .50          1.05
                                                          ----------    ---------     ----------    -----------
      Total............................................. $   1.42      $   1.66      $  1.77      $   2.14
                                                          ----------    ---------     ----------    -----------
Cash Operating Margin (per Mcfe)........................ $    .59           .77      $  1.82      $   1.19

Other (per Mcfe):
Depreciation, depletion and amortization - oil and gas
production.............................................. $    .43      $    .43      $   .36      $    .58

Estimated Net Proved Reserves (as of the respective
   period-end):
Natural gas (Bcf).......................................     17.3          19.3         49.1          68.6
Oil (MMbls).............................................      1.9           1.6          3.9           3.9
Total (Bcfe)............................................     28.7          29.2         72.5          91.8
Reserve Life (in years)/(2)/............................      9.1          14.1         15.8          12.8
Estimated Future Net Revenues ($MM)/(2)//(3)/...........     33.4          50.1        492.3         155.7
Present Value ($MM)/(2)//(3)/...........................     25.3          30.5        284.2          71.0
Standardized measure of discounted future net cash flows     19.2          22.9        186.3          48.5
($mm)/(4)/
</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.

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

/(3)/ The prices used in calculating Estimated Future Net Revenues and the
      Present Value are determined using prices as of period end. Estimated
      Future Net Revenues and the Present Value give no effect to federal or
      state income taxes attributable to estimated future net revenues. See
      "Item 2 - Reserves."

                                      23

<PAGE>

/(4)/ The standardized measure of discounted future net cash flows gives effect
      to federal and state income taxes attributable to estimated future net
      revenues.

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. 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.

     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.

                                      24

<PAGE>

     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--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
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.

                                      25

<PAGE>

             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%.

                                      26

<PAGE>

RESULTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR
ENDED DECEMBER 31, 1999

             Oil and Gas Sales. Oil and gas sales in the year ended December 31,
2000 increased 96% to $4,153,934 compared to the year ended December 31, 1999,
due to increased prices for oil and gas, which accounted for 48% of the
increase, and increased production of gas and oil, which accounted for 52% of
the increase. The average price per barrel of oil and mcf of gas received in
2000 was $21.33 and $3.57, respectively, compared to $16.73 and $2.09 in the
year of 1999. During 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 by $596,970. Oil production for 2000 was approximately the same as
production for the prior year. Gas production increased to 710 MMcf compared to
443 MMcf for the year of 1999, an increase of 60%. Increased production in 2000
resulted from new production and the reworking of certain wells.

             Lease Operations. Lease operations expense increased $246,600 in
2000 to $1,207,095, a 26% increase compared to 1999. Increased expense resulted
from additional wells that were recompleted or drilled. Lease operations expense
on an equivalent unit of production basis was $1.04 per Mcfe in 2000 compared to
$1.11 per Mcfe for 1999. This decrease resulted from an increase in production.

             Production and Severance Taxes. Production and severance taxes
increased 128% to $260,063 in 2000 compared to $114,294 in 1999. 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 decreased $4,021 to $420,488 in 2000, down 1% from
1999.  This decrease is due primarily to a decrease in the depletion rate for
2000 largely offset by higher production levels. The oil and gas depreciation,
depletion and amortization rate per equivalent unit of production was $.30 per
Mcfe in 2000 compared to $.43 per Mcfe in 1999.

             Interest. Interest expense for the year 2000 was $664,713 compared
to $498,199 for the year of 1999. This increase is primarily attributable to
higher average long term debt balances outstanding during 2000 as well as an
increase in interest rates.

             General And Administrative Expense. General and administrative
expense for 2000 was $578,641 compared to $368,824 for 1999, an increase of 57%.
This increase of $209,817 was the result of an increase in salaries of $76,988
and an increase in other general and administrative expense of $45,259. The
salary increase was a result of an increase in administrative salaries of
$143,496 with the addition of administrative personnel but a decrease in
operations salaries of $66,508 as a result of a reduction in operations
personnel. General and administrative expense per equivalent unit of production
was $.50 per Mcfe for the 2000 period compared to $.42 per Mcfe for the
comparable period in 1999.

                                      27

<PAGE>

             Income Taxes.  Income tax expense for year of 2000 was $52,000.
This increase resulted from company net income in 2000 exceeding prior year
cumulative losses.

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. As of December 31, 2001, these proceeds have been fully used, primarily
for development drilling. As a result of uncertainties relating to pending
litigation with a former drilling contractor, we are unable to obtain additional
advances to drill or for other purposes and are in default under the terms of
our credit facility. Due to these liquidity considerations, our independent
auditor has qualified its audit opinion on our 2001 financial statements due to
uncertainties about our ability to continue as a going concern. See "Liquidity
and Financing Considerations."

CASH FLOW--YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 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. EBITDA in the year ended December 31, 2001 was $2,653,367 compared
to $2,145,512 in 2000, an increase of 24%. This increase resulted primarily from
increases in production and oil and gas prices. EBITDA is defined as income
(loss) before interest, income taxes, depreciation, depletion and amortization.
We believe that EBITDA is a financial measure commonly used in the oil and gas
industry and we use it and expect investors to use it as an indicator of a
company's ability to service and incur debt. However, EBITDA should not be
considered in isolation or as a substitute for net income, cash flows provided
by operating activities or other data prepared in accordance with accounting
principles generally accepted in the United States of America, or as a measure
of a company's profitability or liquidity. EBITDA measures as presented may not
be comparable to other similarly titled measures of other companies.

                                      28

<PAGE>

CASH FLOW--2000 COMPARED TO 1999

         In 2000 we expended $2,177,335 in investing activities compared to
$685,060 in 1999. The 1999 year included a $199,860 in acquisition costs of
properties, and $582,047 of development costs. Net cash provided by operating
activities in 1999 was $618,759 compared to $1,394,168 in 2000, reflecting
significantly increased oil and gas sales. Financing activities provided
$491,724 in cash flow in 1999, including approximately $690,604 in net
borrowings and $220,785 in drilling advances, after repurchase of stock from a
former shareholder in the amount of $399,110. Financing activities provided
$277,997 in 2000.

         EBITDA in 1999 was $718,078 compared to $2,145,512 in 2000, primarily
reflecting increased production and oil and gas prices.

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.

         Effective December 17, 2001, as a result of a review of our proved
reserves, the Borrowing Base was increased to $10 million, making an additional
$3.7 million available for borrowing to pursue our development plan. As of
December 31, 2001, we had $6.3 million outstanding under the facility. We
borrowed the additional $3.7 million subsequent to year end and had $10 million
outstanding at March 31, 2002.

         Borrowings bear interest at the prime rate. 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:

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

   .            Require us to maintain a quarterly 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

                                      29

<PAGE>

                income plus depreciation, depletion and amortization plus
                interest expense divided by quarterly principal reduction
                requirements plus interest.

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

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

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

   .            Prohibit payment of dividends or repurchases of stock.

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

   .            Prohibit material changes in management.

         We are in default of the adjusted current ratio and debt service
coverage covenants as of December 31, 2001. Subsequent to December 31, 2001, as
described under "Legal Proceedings", Nabors Drilling filed liens against certain
properties in East Texas which also constituted an event of default. As a result
of these defaults which have not been waived as of April 15, 2002, the liability
owed to the bank under the credit facility has been classified as current
liability as of December 31, 2001. As of April 15, 2002, the bank had not
demanded repayment of this borrowing.

WORKING CAPITAL

         At December 31, 2001, we had a working capital deficit of $12,020,568.
On a pro forma basis if our bank debt were not in default, our working capital
deficit as of December 31, 2001 would have been $5,744,568. Total long-term debt
outstanding at December 31, 2001 was $6.3 million, representing 22% of our total
capitalization.

SHAREHOLDER LOANS

         Prior to the closing of the February 12, 2001 initial public offering,
Ken L. Kenworthy, Jr. had two loans outstanding to the company in the aggregate
amount of $427,500 which were originated in 1999 in order to fund a purchase of
stock from a former shareholder and provide working capital. These loans bore
interest at a rate approximating the prime rate and were repaid in February 2001
with the proceeds of the initial public offering.

COMMITMENTS AND CAPITAL EXPENDITURES

         Other than obligations under our credit facility, our commitments for
capital expenditures relate to planned development of oil and gas properties.
Except as described below with respect to our former drilling contract with
Nabors, we have not entered into drilling or development commitments until such
time as a source of funding for such commitments is known to be

                                      30

<PAGE>

available, either through financing proceeds, internal cash flow, additional
funding under our bank credit facility or working capital. See "Legal
Proceedings".

         On May 29, 2001, we entered into a drilling contract with Nabors
Drilling USA LP, 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 described under "Legal Proceedings". We terminated this contract on December
3, 2001 and have instituted litigation against Nabors for damages. Nabors has
asserted counterclaims for approximately $9 million in damages. The outcome of
this litigation is uncertain.

         During 2001, 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. Additional sources of financing will
likely be necessary in 2002 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.

LIQUIDITY AND FINANCING CONSIDERATIONS

         As described elsewhere herein, we are currently in default under our
bank credit facility, primarily due to uncertainties associated with the pending
litigation with Nabors which in turn has resulted in a going concern
qualification in our auditors' report on our 2001 financial statements. The bank
had not demanded payment as of April 15, 2002. We have in the past and may in
the future continue to pursue a consensual resolution of our disputes with
Nabors, but it is impossible to determine whether a mutually satisfactory
agreement can be reached. In the absence of such an agreement, we will continue
the litigation with Nabors and we will pursue alternative sources of financing
including joint ventures, property sales or other sources of financing to
provide funding for our drilling program. We have initiated a process to
potentially sell a portion of our proved producing and proved undeveloped
reserves. We will also pursue additional debt and equity financings to
complement our expected continued positive cash flow in order to reduce past due
accounts payable and continue our drilling program. 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. We believe our assets, including all of
our reserves, have values sufficient to meet all of our liabilities, including
our bank debt and contingencies related to Nabors. We expect that our current
cash flow, depending on oil and gas prices, will be sufficient to meet current
operating expenses pending resolution. 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 50% of our total production. The gains and losses realized as a result
of these activities are

                                      31

<PAGE>

substantially offset in the cash market when the commodity is delivered. During
2000, we hedged 5,000 barrels per month of oil at a fixed price of $20.25 per
barrel, representing approximately 80 % of our monthly oil production and
approximately 30% of our total production. This hedge reduced our average oil
price for 2001 from $29.24 to $21.33 per Bbl. For the year ended December 31,
2000, we hedged 20,000 MMBtu of natural gas per month at a fixed price of $4.70
per MMBtu. These arrangements hedge 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. For 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 manage
approximately 52% of our estimated monthly gas production based on our December
31, 2001 reserve report.

IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED

         In July 2001, the Financial Accounting Standards Board issued new
pronouncements: SFAS 141, "Business Combinations;" SFAS 142, "Goodwill and Other
Intangible Assets;" and SFAS 143, "Accounting for Asset Retirement Obligations."
SFAS 141, which requires the purchase method of accounting for all business
combinations, applies to all business combinations initiated after June 30, 2001
and to all business combinations accounted for by the purchase method that are
completed after June 30, 2001. SFAS 141 will not apply to the Company unless it
enters into a future business combination. SFAS 142 requires that goodwill as
well as other intangible assets be tested annually for impairment. In addition,
the Statement eliminates the current requirement to amortize goodwill or
intangible assets with indeterminate lives. The Company adopted SFAS 142 on
January 1, 2002. As of that date, the Company did not have any recorded goodwill
or intangible assets. 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 does not expect SFAS 143 to materially impact its reported
results.

         SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets," (SFAS 144) was effective for the Company for the fiscal year beginning
January 1, 2002, and addresses accounting and reporting for the impairment or
disposal of long-lived assets. SFAS 144 supersedes SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long Lived Assets to be Disposed Of"
and APB Opinion No. 30, "Reporting the Results of Operations - Reporting the
effects of Disposal of a Segment of a Business." SFAS 144 retains the
fundamental provisions of SFAS No. 121 and expands the reporting of discontinued
operations to include all components of an entity with operations that can be
distinguished from the rest of the entity and that will be eliminated from the
ongoing operations of the entity in a disposal transaction. The adoption of the
standard did not have a material impact on its financial statements.

                                      32

<PAGE>

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.

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 as a going concern.

         As discussed above, we are in default on our bank debt as a result of
uncertainties arising from litigation and our ability to continue 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. In
addition, we do not have the financial resources to pursue further drilling.
Until these uncertainties are resolved, our ability to implement our business
plan will be materially adversely affected and our financial condition will be
impaired.

                                      33

<PAGE>

There is litigation pending that may have a material adverse effect on the
Company if adversely determined.

         There is a legal proceeding pending in the United States District Court
for the Eastern District of Texas, against us and our President, Ken L.
Kenworthy, Jr., alleging fraud and breach of implied contract and seeking
damages relating to a claimed interest in a Harrison County oil and gas well. In
a related proceeding, we filed a motion to reopen the PPMI/ORMI bankruptcy
proceeding to institute adversary proceedings seeking orders declaring that we
purchased the oil and gas property that is at issue free and clear of the
interest claimed by the plaintiffs. The motion was denied and we have filed a
notice of appeal on the denial.

         We have also 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 has filed a counterclaim
against us. If these actions are adversely determined, they could have a
material adverse effect on the Company. See "Item 3. Legal Proceedings".

Our drilling program in the Cotton Valley formation in east Texas relies heavily
on preliminary drilling results from wells drilled in 2001.

         Our current drilling plan relies heavily on the successful development
of the Pettit, Travis Peak and Cotton Valley formations in our East Texas
properties. As of December 31, 2001, we have successfully drilled 10 wells which
indicate the presence of proved reserves in these formations. Although we have
established regular production from these wells, as of December 31, 2001, this
production history is limited. More significant production history is necessary
to fully evaluate the reserve potential of these wells. There is no assurance
that the additional wells we drill in these formations will encounter
commercially productive reservoirs. Our future performance will be affected by
the results of our Pettit, Travis Peak and Cotton Valley drilling.

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

                                      34

<PAGE>

loss of the services of either of them could adversely affect our business. In
addition, it is a default under our credit agreement if there is a significant
change in management or ownership.

We have limited operating history.

         We were organized in 1998 and have been in operation for less than four
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:

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

       . 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

       . 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,
his brother and one other person. 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:

         . production is less than expected;

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

         . there is a change in the expected differential between the underlying
           price in the hedging agreement and actual prices received.

                                      35

<PAGE>

         In addition, these hedging arrangements may limit the benefit we would
receive from increases in the prices for oil and natural gas. If we choose not
to engage in hedging arrangements in the future, we may be more adversely
affected by changes in oil and natural gas prices than our competitors who
engage in hedging arrangements.

Our 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.

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 2000, we received gas and oil prices at the wellhead ranging from
$1.44 to $5.99 per Mcf and $23.73 to $25.35 per Bbl. In 2001, we received gas
and oil prices ranging from $2.22 to $9.48 per Mcf and $17.88 to $29.18 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:

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

         . storage availability;

         . weather conditions;

         . market uncertainty;

         . domestic and foreign governmental regulations;.

         . the availability and cost of alternative fuel sources;

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

         . the price of foreign oil and natural gas;

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

                                      36

<PAGE>

         . 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.

         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.

                                      37

<PAGE>

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.

Our future performance depends upon our ability 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 may not
be able to make the necessary capital investment to maintain or expand our oil
and natural gas reserves if cash flows from operations are reduced, due to lower
oil and natural gas prices or otherwise, or if external sources of capital
become limited or unavailable. In addition, our drilling activities are subject
to numerous risks, including the risk that no commercially productive oil or gas
reserves will be encountered. We expect to also pursue property acquisition
opportunities. We cannot assure you that we will successfully consummate any
future acquisition, that we will be able to acquire producing oil and natural
gas properties that contain economically recoverable reserves or that any future
acquisition will be profitably integrated into our operations.

Operational risks in our business are numerous and could materially impact us.

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

         . the presence of unanticipated pressure or irregularities in
           formations;

         . accidents;

         . title problems;

         . weather conditions;

         . compliance with governmental requirements; and

                                      38

<PAGE>

         . shortages or delays in the delivery of equipment.
           Also, our ability to market oil and natural gas production depends
           upon numerous factors, many of which are beyond our control,
           including:

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

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

         . 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:

         . injury or loss of life;

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

         . pollution or other environmental damage;

         . clean-up responsibilities;

         . regulatory investigation and penalties; and

         . other losses resulting in suspension of our operations.

         In accordance with customary industry practice, we maintain insurance
against some, but not all, of the risks described above with a general liability
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.

                                      39

<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:

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

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

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

         . blowouts, cratering and explosions.

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

Competition in the oil and gas industry is intense, and we are smaller 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.

                                      40

<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 2002 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, 2001.

ITEM 10.      EXECUTIVE COMPENSATION

         The information required under item 10 will be contained in the proxy
statement for the 2002 Annual Meeting of Shareholders and is incorporated herein
by reference.

                                      41

<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 2002 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 2002 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
                    the Registration Statement on Form SB-2, File No. 333-49328)
         4.3        Form of Lock-up Agreement (Incorporated by reference to
                    Exhibit 4.3 to the Registration Statement on Form SB-2, File
                    No. 333-49328)
         4.4        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)
         10.1*      Letter Agreement between GMX and Jon Stromberg relating to
                    issuance of 6,754 shares of GMX common stock (Incorporated
                    by reference to Exhibit 10.1 to the Registration Statement
                    on Form SB-2, File No. 333-49328)
         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)

                                      42

<PAGE>

         10.3       Restated Credit Agreement dated October 31, 2000 with Local
                    Oklahoma Bank, N.A. (Incorporated by reference to Exhibit
                    10.3 to the XSRegistration 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)
         10.5       Form of Director Indemnification Agreement (Incorporated by
                    reference to Exhibit 10.5 to the Registration Statement on
                    Form SB-2, File No. 333-49328)
         10.6       Drilling Contract with Nabors Drilling USA, L.P.
                    (Incorporated by reference to Exhibit 10.8 to the
                    Registration Statement on Form SB-2, File No. 333-63586)
         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.

         (b)        No reports on Form 8-K were filed during the last quarter of
the period covered by this report.

                                      43

<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 15, 2002                   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 15, 2002
------------------------------                             ---------------------
Ken L. Kenworthy, Jr.

/s/ Ken Kenworthy, Sr.           Executive Vice President,    April 15, 2002
------------------------------                             ---------------------
Ken Kenworthy, Sr.               Chief Financial Officer
                                 and Director

/s/ Steven Craig                 Director                     April 15, 2002
------------------------------                             ---------------------
Steven Craig

/s/ T. J. Boismier               Director                     April 15, 2002
------------------------------                             ---------------------
T. J. Boismier

/s/ Steve Roney                  Chief Accounting Officer     April 15, 2002
------------------------------                             ---------------------
Steve Roney

                                      44

<PAGE>


                  INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Independent Auditors' Report                                                F-2

Consolidated Balance Sheets, December 31, 2000 and 2001                     F-3

Consolidated Statements of Operations,

    Years Ended December 31, 2000 and 2001                                  F-4

Consolidated Statements of Changes in Shareholders' Equity,

    Years Ended December 31, 2000 and 2001                                  F-5

Consolidated Statements of Cash Flows,

    Years Ended December 31, 2000 and 2001                                  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, 2000 and 2001 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, 2000 and 2001 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 consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As discussed in Note C to the
financial statements, the Company is not in compliance with certain of its debt
covenants and has a working capital deficiency that raises substantial doubt
about its ability to continue as a going concern. Management's plans in regard
to these matters are also described in Note L. The consolidated 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
March 23, 2002

                                      F-2

<PAGE>

                              GMX RESOURCES INC.
                          CONSOLIDATED BALANCE SHEETS
                          DECEMBER 31, 2000 AND 2001

<TABLE>
<CAPTION>
                                                                         2000          2001
                                                                     ------------  ------------
<S>                                                                 <C>           <C>
                                         ASSETS

CURRENT ASSETS:
    Cash                                                            $     30,043  $      3,725
    Accounts receivable--interest owners                                 117,289       194,180
    Accounts receivable--oil and gas revenues                            945,388     1,116,930
    Inventories                                                           86,312       243,799
    Prepaid expenses and other current assets                             19,673        98,512
                                                                     ------------  ------------
               Total current assets                                    1,198,705     1,657,146
                                                                     ------------  ------------

OIL AND GAS PROPERTIES, AT COST, BASED ON THE FULL COST METHOD OF
 ACCOUNTING FOR OIL AND GAS PROPERTIES                                 9,971,628    34,113,269
    Less accumulated depreciation, depletion, and amortization        (1,108,938)   (1,964,654)
                                                                     ------------  ------------
                                                                       8,862,690    32,148,615
                                                                     ------------  ------------

OTHER PROPERTY AND EQUIPMENT                                             600,822     3,159,963
    Less accumulated depreciation                                       (154,321)     (317,302)
                                                                     ------------  ------------
                                                                         446,501     2,842,661
                                                                     ------------  ------------

Other assets                                                             462,386        71,252
                                                                     ------------  ------------

               TOTAL ASSETS                                         $ 10,907,282  $ 36,719,674
                                                                     ============  ============

                           LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
    Accounts payable                                                $    579,137  $  6,880,869
    Accrued expenses                                                      58,054       185,763
    Accrued interest                                                      65,215        26,791
    Revenue distributions payable                                        595,888       304,291
    Current portion of long-term debt                                  1,261,364     6,280,000
                                                                     ------------  ------------
               Total current liabilities                               2,559,658    13,677,714

LONG-TERM DEBT, LESS CURRENT PORTION                                   6,312,500           -

OTHER LIABILITIES                                                        146,331       304,397

DEFERRED INCOME TAXES                                                     52,000       263,000

SHAREHOLDERS' EQUITY:
    Preferred stock, par value $.01 per share, 500,000 shares
    authorized, none outstanding                                             -             -
    Common stock, par value $.001 per share--authorized 50,000,000
    shares; issued 3,000,000 shares in 2000 and 6,550,000 in 2001;
    outstanding 3,000,000 shares in 2000 and 6,550,000 in 2001             3,000         6,550
    Additional paid-in capital                                         1,390,730    20,905,197
    Retained earnings                                                    506,063     1,562,816
                                                                     ------------  ------------
               Total shareholders' equity                              1,899,793    22,474,563
                                                                     ------------  ------------

               TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY           $ 10,970,282  $ 36,719,674
                                                                     ============  ============
</TABLE>

See accompanying notes to consolidated financial statements.

                                      F-3

<PAGE>

                              GMX RESOURCES INC.
                     CONSOLIDATED STATEMENTS OF OPERATIONS
                     YEARS ENDED DECEMBER 31, 2000 AND 2001

                                                         2000           2001
                                                     ------------   ------------
REVENUE
    Oil and gas sales                               $  4,153,934   $  5,898,003
    Interest income                                       23,123        198,933
    Other income                                          14,255        355,363
                                                     ------------   ------------
         Total revenue                                 4,191,312      6,452,299
                                                     ------------   ------------

EXPENSES
    Lease operations                                   1,207,095      1,604,559
    Production and severance taxes                       260,064        338,637
    Depreciation, depletion, and amortization            420,488      1,026,498
    Interest                                             664,713        359,118
    General and administrative                           578,641      1,855,736
                                                     ------------   ------------
         Total expenses                                3,131,001      5,184,548
                                                     ------------   ------------

         Income before income taxes                    1,060,311      1,267,751

INCOME TAXES                                              52,000        211,000
                                                     ------------   ------------

         Net Income                                 $  1,008,311   $  1,056,751
                                                     ============   ============

         Net Income Applicable to common shares     $    875,810   $  1,056,751
                                                     ============   ============

         EARNINGS PER SHARE--BASIC                  $       0.48   $       0.21
                                                     ============   ============

         EARNINGS PER SHARE--DILUTED                $       0.29   $       0.20
                                                     ============   ============

         WEIGHTED AVERAGE COMMON SHARES--BASIC         1,822,926      5,148,493
                                                     ============   ============

         WEIGHTED AVERAGE COMMON SHARES--DILUTED       3,469,326      5,179,693
                                                     ============   ============

See accompanying notes to consolidated financial statements.

                                      F-4

<PAGE>

                           GMX RESOURCES INC.
       CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
                 YEARS ENDED DECEMBER 31, 2000 AND 2001

<TABLE>
<CAPTION>
                                                                                            PREFERRED STOCK
                                                                            --------------------------------------------
                                                        COMMON STOCK               SERIES A               SERIES B
                                                   ----------------------   -----------------------  -------------------
                                                     SHARES       AMOUNT     SHARES        AMOUNT     SHARES     AMOUNT
                                                   -----------   --------   ---------   -----------  --------  ---------
<S>                                                 <C>         <C>         <C>        <C>           <C>       <C>
BALANCE AT DECEMBER 31, 1999                        2,176,500   $  2,177     150,000   $     1,500    22,000   $   220

Services rendered in exchange for stock                98,000         98          -             -         -        -
Retirement of preferred shares, Series B                   -          -                              (22,000)     (220)
Retirement of treasury stock                         (725,500)      (726)    (50,000)         (500)       -        -
Conveersion of preferred stock, series A            1,451,000      1,451    (100,000)       (1,000)
Net loss                                                   -          -           -             -         -        -
                                                   -----------   --------   ---------   -----------  --------  ---------

BALANCE AT DECEMBER 31, 2000                        3,000,000      3,000          -             -         -        -

Issuance of units                                   1,250,000      1,250          -             -         -        -
Issuance of shares                                  2,300,000      2,300          -             -         -        -
Net Income                                                 -          -           -             -         -        -
Cumulative effect of change in accounting                  -          -           -             -         -        -
  principle                                                -          -           -             -         -        -
Adjustment for derivative losses reclassified
  into oil and gas sales                                   -          -           -             -         -        -
Change in fair value of derivative instruments             -          -           -             -         -        -
Total comprehensive income
                                                   -----------   --------   ---------   -----------  --------   --------
BALANCE AT DECEMBER 31, 2001                        6,550,000   $  6,550          -    $        -         -    $   -
                                                   ===========   ========   =========   ===========  ========   ==-=====

<CAPTION>
                                                                   RETAINED       ACCUMULATED
                                                    ADDITIONAL     EARNINGS          OTHER                              TOTAL
                                                     PAID-IN     (ACCUMULATED)    COMPREHENSIVE      TREASURY        SHAREHOLDERS'
                                                     CAPITAL       DEFICIT)          INCOME            STOCK            EQUITY
                                                  ------------   -------------   ---------------   --------------   --------------
<S>                                              <C>            <C>                   <C>         <C>              <C>
BALANCE AT DECEMBER 31, 1999                     $  2,042,712   $     (502,248)           -       $   (426,878)    $    1,117,483

Services rendered in exchange for stock                 3,902              -                               -                4,000
Retirement of preferred shares, Series B             (229,781)                                                           (230,001)
Retirement of treasury stock                         (425,652)             -                           426,878                -
Conveersion of preferred stock, series A                 (451)
Net loss                                                  -          1,008,313            -                -            1,008,313
                                                  ------------   --------------  ---------------   --------------   --------------

BALANCE AT DECEMBER 31, 2000                        1,390,730          506,065                             -            1,899,795

Issuance of units                                   8,309,310              -              -                -            8,310,560
Issuance of shares                                 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                               4,919
Total comprehensive income                                                                                          --------------
                                                                                                                        1,056,751
                                                  ------------   --------------  ---------------   --------------   --------------
BALANCE AT DECEMBER 31, 2001                     $ 20,905,197   $    1,562,816            -       $        -       $   23,531,314
                                                  ============   ==============  ===============   ==============   ==============
</TABLE>

        See accompanying notes to consolidated financial statements.

                                      F-5

<PAGE>

                              GMX RESOURCES INC.
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                     YEARS ENDED DECEMBER 31, 2000 AND 2001

<TABLE>
<CAPTION>
                                                                       2000          2001
                                                                   ------------  ------------

<S>                                                               <C>           <C>
CASH FLOWS DUE TO OPERATING ACTIVITIES
    Net income                                                    $  1,008,311  $  1,056,751
    Adjustments to reconcile net income to
     net cash provided by operating activities:
            Depreciation, depletion, and amortization                  420,488     1,026,498
            Deferred income taxes                                       52,000       211,000
            Gain on sale of other property and equipment               (13,789)         (319)
            Gain from demutualization of insurance company                 -         (74,124)
            Stock to be issued for consulting services                   4,000           -
            Amortization of loan costs                                  61,457        12,702
            Decrease (increase) in:
                Accounts receivable                                   (325,136)     (248,433)
                Inventory and prepaid expenses                          (4,706)     (162,202)
                Other assets                                               -         (26,276)
            Increase (decrease) in:
                Accounts payable                                        68,126     6,267,630
                Accrued expenses and other liabilities                  52,140       244,970
                Revenue distributions payable                           71,277      (291,597)
                                                                   ------------  ------------

                    Net cash provided by operating activities        1,394,168     8,016,600
                                                                   ------------  ------------

CASH FLOWS DUE TO INVESTING ACTIVITIES
    Additions to oil and gas properties                             (2,086,641)  (24,385,466)
    Additions to property and equipment                               (125,294)   (2,575,096)
    Proceeds from sale of oil and gas properties                        12,100       243,824
    Proceeds from sale of other property and equipment                  22,500        15,953
                                                                   ------------  ------------

                    Net cash used in investing activities           (2,177,335)  (26,700,785)
                                                                   ------------  ------------

CASH FLOWS DUE TO FINANCING ACTIVITIES
    Proceeds from borrowings                                         8,473,500     1,765,000
    Payments of debt issue costs                                       (15,000)      (22,500)
    Payments on debt                                                (7,281,449)   (3,058,864)
    Retirement of preferred stock                                     (230,001)          -
    Other assets                                                      (448,268)          -
    Drilling advances                                                 (220,785)          -
    Issuance of equity                                                     -      19,974,231
                                                                   ------------  ------------

                    Net cash provided by financing activities          277,997    18,657,867
                                                                   ------------  ------------

Net decrease in cash                                                  (505,170)      (26,318)

CASH AT BEGINNING OF YEAR                                              535,213        30,043
                                                                   ------------  ------------

CASH AT END OF YEAR                                               $     30,043  $      3,725
                                                                   ============  ============

CASH PAID FOR INTEREST                                            $    614,327  $    474,444
                                                                   ============  ============
</TABLE>

See accompanying notes to consolidated financial statements.

                                      F-6

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

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.

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.

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 ten years.

GMX accounts for its non-oil and natural gas long-lived assets in accordance
with the provisions of Financial Accounting Standards Board Statement No. 121,
"Accounting for the Impairment of Long-lived Assets and Assets to be Disposed
of." Statement 121 requires that long-lived assets and identifiable intangibles
be reviewed for impairment

                                      F-7

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

whenever events of changes in circumstances indicate that the carrying amount of
an asset may not be recoverable. Recoverability of assets to be held and used is
measured by a comparison of the carrying amount of an asset to future
undiscounted net cash flows expected to be generated by the asset. If such
assets are considered to be impaired, the impairment to be recognized is
measured by the amount by which the carrying amount of the assets exceeds the
fair value of the assets. Assets to be disposed of are reported at the lower of
the carrying amount or fair value less the cost to sell.

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.

CAPITALIZED INTEREST:  Interest of $59,715 and $64,410 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 2000 and
2001, 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.

                                      F-8

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

HEDGING AND RISK MANAGEMENT ACTIVITIES:  The Company has periodically entered
into oil and gas price swaps to manage its exposure to oil and gas price
volatility. The instruments are usually placed with counterparties that the
Company believes are minimal credit risks. The oil and gas reference prices upon
which the risk management instruments are based reflect various market indices
that have a high degree of historical correlation with actual prices received by
the Company.

Prior to January 1, 2001, the Company accounted for its hedging instruments
using the deferral method of accounting. Under this method, realized gains and
losses from the Company's price risk management activities were recognized in
oil and gas revenues when the associated production occurs and the resulting
cash flows were reported as cash flows from operating activities. Gains and
losses on hedging contracts that were closed before the hedged production occurs
were deferred until the production month originally hedged. In the event of a
loss of correlation between changes in oil and gas reference prices under a
hedging instrument and actual oil and gas prices, a gain or loss was recognized
currently to the extent the hedging instrument had not offset changes in actual
oil and gas prices.

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.

                                      F-9

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

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 2000, diluted earnings per share reflect
the potential dilution that could occur if the Company's then outstanding
convertible preferred stock were converted to common stock, net of preferred
dividends associated with the dilutive convertible preferred stock. The weighted
average dilutive shares included in the 2000 period were 1,646,400. The weighted
average dilutive shares included in the 2001 period were 31,200.

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

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, 2001, 2000, and
1999.

                                      F-10

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

NOTE B--PROPERTY AND EQUIPMENT

Property and equipment included the following:

<TABLE>
<CAPTION>
                                                                        December 31,
                                                            ------------------------------------
                                                                  2000                2001
                                                            ----------------   -----------------
<S>                                                        <C>                <C>
Oil and gas properties:
   Subject to amortization                                 $    9,179,489     $    32,872,557
   Not subject to amortization:
      Acquired in 2001                                                 --           1,000,406
      Acquired in 2000                                            335,259              62,158
      Acquired in 1999                                            188,379              36,943
      Acquired in 1998                                            268,501             141,205
   Accumulated depreciation, depletion, and amortization       (1,108,938)         (1,964,654)
                                                            ----------------   -----------------
       Net oil and gas properties                               8,862,690          32,148,615
                                                            ----------------   -----------------
Other property and equipment                                      600,822           3,159,963
Less accumulated depreciation                                    (154,321)           (317,302)
                                                            ----------------   -----------------

       Net other property and equipment                           446,501           2,842,661
                                                            ----------------   -----------------
         Property and equipment, net of accumulated
            Depreciation, depletion, and amortization      $    9,309,191     $    34,991,276
                                                            ================   =================
</TABLE>

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

<TABLE>
<CAPTION>
                                                                    For The Year Ended
                                                                        December 31,
                                                            ------------------------------------
                                                                  2000                2001
                                                            ----------------   -----------------
<S>                                                        <C>                <C>

Depreciation, depletion, and amortization of oil
   and gas properties                                      $      352,641     $       855,716
Depreciation of other property and equipment                       67,847             170,782
                                                            ----------------   -----------------

           Total                                           $      420,488     $     1,026,498
                                                            ================   =================
</TABLE>

                                      F-11

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

NOTE C--LONG-TERM DEBT

<TABLE>
<CAPTION>
                                                                            December 31,
                                                               -------------------------------------
                                                                     2000                 2001
                                                               ----------------    -----------------
<S>                                                           <C>                 <C>
Note payable to bank, maturity date of May 1, 2003,
bearing a variable interest rate (10% and 4.75% as of
December 31, 2000 and 2001, respectively)  collateralized
by producing oil and gas properties                           $    7,145,000      $     6,280,000

Notes payable to Shareholder, bearing variable interest
rates as of December 31, 2000, collateralized by
unproved properties                                                  427,500                   --
Other                                                                  1,364                   --
                                                               ----------------    -----------------
                                                                   7,573,864            6,280,000
Current portion - unrelated parties                               (1,261,364)          (6,280,000)
                                                               ----------------    -----------------
                                                              $    6,312,500      $             0
                                                               ================    =================
</TABLE>

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. As of December 31, 2000, the
Borrowing Base was $7,145,000 which began reducing by $105,000 per month
beginning December 1, 2000. Effective December 17, 2001, as a result of our
review of our proved reserves, the Borrowing Base was increased to $10 million,
making an additional $3.7 million available for borrowing to pursue our
development plan. Borrowings bear interest at the prime rate plus 50%. 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. At December 31, 2000, the Company had borrowed $7,145,000
under the credit facility, leaving no availability for borrowings to fund
development drilling obligations based on the existing Borrowing Base.

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 Company
received a waiver as of December 31, 2000 for noncompliance with the current
ratio requirement.

As of December 31, 2001, the Company is not in compliance with the current ratio
and debt service covenants included in the 2000 Credit Facility. Additionally
subsequent to December 31, 2001, and as discussed in Note E, liens have been
filed against several of the Company's properties. The filing of the liens
creates an additional instance of

                                      F-12

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

noncompliance with the 2000 Credit Facility covenants. The lender has not waived
any of 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 a result of the technical default, the borrowings
outstanding under the facility have been reflected as current in the
accompanying consolidated balance sheet.

Subsequent to December 2001, the Company did borrow an additional $3.7 million
under the facility (fully advancing the borrowings to the $10 million borrowing
base determined by the lender) to reduce the Company's past due accounts
payable.

1998 Credit Facility
On February 18, 1998, the Company entered into a secured credit facility that
provided for a line of credit up to $20,000,000, subject to a Borrowing Base
which was based on a periodic evaluation of oil and gas reserves. The amount of
credit that was available at any one time under the credit facility was the
lesser of the Borrowing Base or the amount of the Commitment. As of December 31,
1999, the Borrowing Base was $6,500,000. The credit facility had a maturity date
of January 31, 2002. The Company had the option of either borrowing at LIBOR or
the base rate which approximated the prime rate, in either case plus a margin
ranging from .50% to 3.25% depending upon the amount of advances outstanding in
relation to the Borrowing Base. The credit facility required payment of an
annual facility fee equal to 0.375% to 0.5% basis points of the amount of the
Commitment. The Company was obligated to make monthly principal payments in
amounts determined by the lender after taking into consideration the expected
reductions in the Borrowing Base as a result of production. Borrowings under the
credit agreement were secured by substantially all of the Company's oil and gas
properties.

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

The credit facility was personally guaranteed by the President and Executive
Vice-President. The amount of their guarantees was limited to $750,000 each. The
facility was terminated on October 31, 2000 and replaced with the 2000 Credit
Facility.

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.

                                      F-13

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

At December 31, 2001, the Company had the following carryforwards available to
reduce future income taxes:

Federal                                                  $  21,568,000
State                                                        1,409,000
Statutory depletion                                          1,547,000

All of the net operating loss and statutory depletion carryforward amounts shown
above have been utilized for financial purposes to offset deferred tax
liabilities. The net operating loss carryforwards expire from 2018 to 2020.
Statutory depletion carryforwards do not expire.

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.

As of December 31, 2000, the Company's deferred tax liability of $861,000 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 $809,000 was primarily the result of the
Company's net operating loss and statutory depletion carryforwards.

As of December 31, 1999, the company had recognized a full valuation allowance
of $77,000 for the net operating loss carryforwards that have been generated
since inception to the extent that the net operating loss carryforwards exceed
the difference between financial carrying value and tax basis for the Company's
property and equipment. During 2000, the Company determined, based upon
projections of future taxable income, that the utilization of the net operating
loss and statutory depletion carryforwards was more likely than not and fully
reduced the valuation allowance.

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,
                                            ---------------------------------
                                                 2000               2001
                                            ---------------   ---------------
U.S. statutory tax rate                               34%               34%
Statutory depletion                                  (22)              (16)

Reversal of valuation allowance                       (7)               --
Other                                                 --                (1)
                                            ---------------   ---------------
Effective income tax rate                              5%               17%
                                            ===============   ===============

                                      F-14

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

NOTE E--COMMITMENTS AND CONTINGENCIES

The Company is party to various 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.

On March 1, 2001, Larry Miller and certain other parties filed an action in the
United States District Court for the Eastern District of Texas, Marshall
Division, against us and our President, Ken L. Kenworthy, Jr., alleging fraud
and breach of implied contract and seeking damages relating to a claimed
interest in an oil and gas well we drilled in Harrison County, Texas in 2000.
The Plaintiff claims we permitted Downs No. 1 well to cease producing and the
relevant leases to expire and subsequently drilled another well in lieu of
reworking or redrilling the well. The Plaintiffs claim they were entitled to an
interest in the well and seek actual damages of $750,000, unspecified punitive
damages and attorney fees. We have denied these allegations and asserted that
the old leases expired due to lack of production after numerous attempts were
made to restore the old well problem. We have also claimed that we purchased the
leases in question out of the PPMI/ORMI bankruptcy proceeding free and clear of
all unrecorded claims. In a related proceeding, on October 9, 2001, we filed a
motion to reopen the bankruptcy proceeding and filed a notice of appeal on the
denial of such motion on January 22, 2002. We moved to reopen the first
proceeding in order to institute adversary proceedings seeking orders declaring
that we purchased the oil and gas property that is at issue in this lawsuit free
and clear of the interest claimed by the plaintiffs. We intend to vigorously
defend this action and do not believe it will have any material adverse effect
on our financial condition or results of operations.

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 contracts and are
seeking damages in an amount representing specified excess cost and loss of
profits occasioned by Nabors' acts, plus attorneys' fees. A counterclaim 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
seeks damages of $8.9 million, consisting of $1.8 million in unpaid invoices and
$7.1 million for contract termination fees, plus interest and attorneys' fees.

In February 2002, Nabors filed materialmen's liens against seven wells asserting
claims for amounts due for drilling services on these wells in the aggregate
amount of $1.8 million and demanded payment by March 21, 2002. The Company
intends to dispute

                                      F-15

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

these claims based on its position that Nabors' draw on a $1 million letter of
credit to secure payment should have been applied to the unpaid invoices and
that some of the amounts are not otherwise properly owing.  Nabors has
threatened to foreclose its lien if it is not paid, which if successful, could
result in the Company losing all or a portion of its interest in these wells.

This action is still in the preliminary stages. We intend to vigorously
prosecute and defend this action, but the ultimate outcome is not determinable.
If Nabors prevails in this litigation, it could have material adverse effect on
our financial condition, results of operations and prospects.

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:

   2002                                                      97,298
   2003                                                     100,673
   2004                                                      16,870
                                                        -------------
      Total                                           $     214,841
                                                        =============

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

   2000                                               $      59,630
   2001                                                      82,739

NOTE F--SHAREHOLDERS' EQUITY

The Series A preferred issue (par value $.01 per share) was convertible into
14.51 shares of common stock. Dividends were $.325 per year per share and
cumulative. The Series B issue (par value $.01 per share) was to pay dividends
at $6.00 per share per year and also was cumulative. Series B could be redeemed
at the option of the Company. The redemption price was as follows:

By December 31, 1999                                       1,000,000
By December 31, 2000                                       1,500,000
By December 31, 2001                                       2,000,000
After December 31, 2001                                    2,200,000

No shares were redeemed as of December 31, 1999. After December 31, 2001, the
shares were convertible into shares of common stock representing a specified
increasing percentage of the shares outstanding, ranging from 593,000 shares to
1,089,000 shares as of January 2003. Cumulative dividends in arrears, but not
declared, at December 31,

                                      F-16

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

1999 were $32,500 and $132,000 for Series A and Series B, respectively. All
dividend arrearages were eliminated in the conversion of the Series A and the
purchase of the Series B as described below.

On October 25, 2000, the Company purchased all of the Series B preferred stock
for $230,000 and retired such shares. Additionally, the holders of the Series A
preferred stock converted the Series A preferred stock into 1,451,000 common
shares.

On October 30, 2000, the Company effected a 14.51 for 1 stock split in the form
of a stock dividend. All share amounts disclosed in these consolidated financial
statements reflect this stock split as if it had occurred as of the earliest
period presented.

In March 1999, the Company completed the purchase of 725,500 shares of common
stock and 50,000 shares of Series A preferred stock which was 100% of the
holding of two of the shareholders. The purchase price was $375,000 in cash,
along with one producing well and the surrounding acreage. During 1998, the
Company incurred $9,339 of costs associated with the purchase of the treasury
stock.

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.

                                      F-17

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

Stock option activity for the year ended December 31, 2001 is as follows:

                                                                 Weighted
                                               Number of          average
                                                shares         exercise price
                                           ---------------    -----------------
Balance as of December 31, 2000
                                                      --                    --
     Granted                                     170,000    $             5.72
     Exercised                                        --                    --
     Forfeited                                    20,000    $             6.26
     Expires                                          --                    --
                                           ---------------    -----------------
Balance as of December 31, 2001                  150,000    $             5.65
                                           ---------------    -----------------

At December 31, 2001, the range of exercise prices and weighted-average
remaining contractual life of outstanding options was $4.03 to $8.00 and 9.43
years, respectively.

At December 31, 2001, the number of options exercisable was 150,000 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
                                                        ------------------
Net (loss) earnings as reported
                                                      $     1,056,751
Pro forma                                                     918,928

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.

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

                                      F-18

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

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.

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, 2000 and 2001 were as follows:

                                               2000          2001
                                               ----          ----

Teppco Crude                                   32.2%         28.7%
Koch Gateway Pipeline                          25.1%         47.9%

NOTE H--DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

During 2000, the Company utilized swap arrangements to hedge a portion of its
exposure to price volatility from producing crude oil. 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 oil sales. Payments by the Company in 2000 totaled $596,670.

The Company had a swap arrangement covering 5,000 barrels of crude oil per month
through December 31, 2000 at a price of $20.25 per barrel. The swap arrangement
covered approximately 80% of the Company's expected monthly production. The
company also had a swap arrangement covering 20,000 MMBtu of natural gas per
month through June 2001 at a price of $4.70 per MMBtu which was settled prior to
December 31, 2000. The Company has also 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. These swap agreements covered approximately 52% of the company's expected
monthly production.

The fair value of the financial instrument as of December 31, 2000 was a
liability of approximately $187,800. 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.

                                      F-19

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

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.

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, 2001 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 2001 derivative instruments did not qualify for hedge accounting. As a
result changes in fair value were reflected in the 2001 consolidated statements
of operations. All instruments were settled prior to December 31, 2001. The net
gain on settlement of $265,313 is reflected as other income.

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.

NOTE J--OIL AND GAS OPERATIONS

Capitalized costs related to the Company's oil and gas producing activities as
of December 31, 2000 and 2001 are:

                                      F-20

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

<TABLE>
<CAPTION>
                                                            2000              2001
                                                      ---------------   ----------------
<S>                                                  <C>               <C>
Unproved properties                                  $      792,139    $     1,240,712
Producing properties                                      9,179,489         32,872,557
                                                      ---------------   ----------------

                                                          9,971,628         34,113,269
Less accumulated depreciation, depletion, and
   amortization                                          (1,108,938)        (1,964,654)
                                                      ---------------   ----------------

           Net capitalized costs                     $    8,862,690    $    32,148,615
                                                      ===============   ================
</TABLE>

Unproved properties include leaseholds under exploration. Producing properties
include mineral properties with proved reserves, development wells, and
uncompleted development well costs. Support equipment and facilities include
costs for pipeline facilities, field equipment, and other supporting assets
involved in oil and gas producing activities. The accumulated depreciation,
depletion, and amortization represent the portion of the assets which has been
charged to expense.

Costs incurred in oil and gas property acquisitions, exploration, and
development activities in 2000 and 2001 are as follows:

<TABLE>
<CAPTION>
                                                            2000              2001
                                                      ---------------   ----------------
<S>                                                  <C>               <C>
Property acquisition costs - unproved                $      335,259    $     2,488,614
Property acquisition costs - proved                         359,753          2,382,548

Development costs                                         1,379,531         19,270,480
                                                      ---------------   ----------------

                                                     $    2,074,543    $    24,141,642
                                                      ===============   ================
</TABLE>

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 2000 and 2001 include revenues and
expenses associated directly with oil and gas producing activities.

<TABLE>
<CAPTION>
                                                            2000              2001
                                                      ---------------   ----------------
<S>                                                  <C>               <C>
Oil and gas sales                                    $    4,153,934    $     5,898,004
Production costs                                          1,467,359          1,943,196
Depreciation, depletion and amortization                    352,641            855,716
Income tax expense                                          405,000            830,000
                                                      ---------------   ----------------
Results of operations for oil and gas
     producing activities                            $    1,928,934    $     2,269,092
                                                      ===============   ================
</TABLE>

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.

                                      F-21

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

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,
2000 and 2001, 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, 2000
   Proved reserves, beginning of period                     1,647             19,278
   Extensions, discoveries, and other additions             2,161             30,409
   Production                                                 (75)              (710)
   Sale of reserves in-place                                   --                 --
   Revisions of previous estimates                           (125)                93
                                                    -----------------    -----------------
   Proved reserves, end of period                           3,858             49,070
                                                    =================    =================
   Proved developed reserves:
       Beginning of period                                  1,083              9,194
                                                    -----------------    -----------------
       End of period                                        1,410             15,352
                                                    -----------------    -----------------
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
                                                    -----------------    -----------------
</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 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

                                      F-22

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

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,
                                                             2000               2001
                                                       ----------------   ----------------
                                                        (In thousands)     (In thousands)
<S>                                                   <C>                <C>
Future cash inflows                                   $     587,789      $      247,148
Future production costs                                     (82,013)            (49,861)
Future development costs                                    (13,466)            (41,609)
Future income tax provisions                               (169,578)            (49,211)
                                                       ----------------   ----------------

     Net future cash inflows                                322,732             106,467
Less effect of a 10% discount factor                       (136,451)            (57,939)
                                                       ----------------   ----------------
     Standardized measure of discounted future
         net cash flows                               $     186,281      $       48,528
                                                       ================   ================
</TABLE>

Oil and condensate prices were based on an equivalent base price of $18.40 per
barrel for benchmark posted West Texas Intermediate Crude Oil at closing on
December 31, 2001. 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 $17.93 per barrel. Natural gas prices were based on an equivalent base price
of $2.56 per million British thermal unit (MMBtu) for the composite Henry Hub
Spot Market benchmark price at closing on December 31, 2001. 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 $2.59 per MMBtu. Future income tax
expenses are computed by applying the appropriate statutory rates to the future
pre-tax net cash flows relating to proved reserves, net of the tax basis of the
properties involved giving effect to permanent differences, tax credits, and
allowances relating to proved oil and gas reserves.  Principal changes in the
standardized measure of discounted future net cash flows attributable to the
Company's proved reserves are as follows:

                                      F-23

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2000 AND 2001

<TABLE>
<CAPTION>
                                                                        December 31,       December 31,
                                                                           2000               2001
                                                                     ----------------   ----------------
<S>                                                                 <C>                <C>
Standardized measure, beginning of year                             $        22,903    $       186,281
Sales of oil and gas, net of production costs                                (2,687)            (4,446)
Net changes in prices and production costs                                   84,709           (200,847)
Extensions and discoveries, net of future development costs                 166,091             22,465
Development costs that reduced future development costs                         900              2,250
Revisions of quantity estimates                                               1,870            (15,718)
Sales of reserves in place                                                       --               (579)
Accretion of discount                                                         3,025             28,416
Other                                                                            --            (44,750)
Net changes in income taxes                                                 (90,530)            75,452
                                                                     ----------------    ----------------
Standardized measure, end of year                                   $       186,281    $        48,524
                                                                     ================    ================
</TABLE>

NOTE L--MANAGEMENT'S PLANS

The Company plans to continue to proceed with the legal proceedings related to
Nabors. A finding in the Company's favor or a settlement with Nabors would
reduce the Company's exposure to amounts asserted as obligations by Nabors. See
Note E.

The Company has initiated a process to potentially sell a portion of its proved
producing and proved undeveloped reserves. The Company will also continue to
pursue additional debt and equity financings to complement the expected
continued positive operating cash flow in order to reduce the Company's past due
accounts payable balance and continue the Company's development program. 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. As a
result of the liquidity issues described above, the Company has reduced its
capital expenditures in the first quarter of 2002.

                                      F-24