<PAGE>

                    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, 2000

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

                        Commission file number 000-32325

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

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

               9600 North Broadway, 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. |_| Yes |X| No

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

The issuer's revenue for the year ended December 31, 2000 was $4,191,312.

The aggregate market value of the voting and non-voting common equity
(excluding warrants) held by non-affiliates at March 28, 2001 was $5,379,844.
This amount was computed using closing price of the issuer's common stock on
March 28, 2001  on the NASDAQ Smallcap Market.

As of March 28, 2001, the issuer had outstanding a total of 4,250,000 shares of
its $0.001 par value Common Stock.

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

                               GMX RESOURCES INC.
                                   Form 10-KSB
                                Table of Contents

<TABLE>
<CAPTION>

                                                                            Page
                                                                            ----

                                     PART I
<S>                                                                         <C>
Item 1.  BUSINESS..............................................................1
         General...............................................................1
         Public Offering.......................................................1
         Business Strategy.....................................................1
         Marketing.............................................................2
         Regulation............................................................3
         Gas Gathering.........................................................5
         Competition...........................................................5
         Facilities............................................................5
         Employees.............................................................5
         Certain Technical Terms...............................................5

Item 2.  PROPERTIES............................................................8
         Reserves.............................................................11
         Costs Incurred and Acquisition and Drilling Results..................13
         Productive Well Summary..............................................14
         Productive Wells.....................................................14

Item 3.  LEGAL PROCEEDINGS....................................................14

Item 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..................15

                                     PART II

Item 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND
               RELATED STOCKHOLDER MATTERS....................................15

Item 6.  MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION............16
         Selected Financial Data..............................................16
         Summary Operating and Reserve Data...................................17
         Results of Operations--Year Ended December 31, 2000 Compared
               to Year Ended December 31, 1999................................18
         Results of Operations for the Year Ended December 31, 1999
               Compared to Year Ended December 31, 1998.......................19
         Capital Resources and Liquidity......................................19
         Commitments and Capital Expenditures.................................22
         Hedging..............................................................22
         Impact of Recently Issued Accounting Standards Not Yet Adopted.......22
         Forward-Looking Statements...........................................23
         Risk Factors Related to GMX..........................................23
         Risks Related to the Oil and Gas Industry............................25

Item 7.  FINANCIAL STATEMENTS.................................................29


                                       i
<PAGE>

<S>                                                                         <C>
Item 8.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
               ACCOUNTING AND FINANCIAL DISCLOSURE............................29

                                    PART III

Item 9.  DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL
               PERSONS; COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT.....29

Item 10. EXECUTIVE COMPENSATION...............................................29

Item 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERSHIP AND MANAGEMENT....29

Item 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.......................30

Item 13. EXHIBITS AND REPORTS ON FORM 8-K.....................................30
</TABLE>


                                       ii
<PAGE>

                                     PART I

Item 1. BUSINESS

General

      GMX is an independent oil and gas company. 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, we have conducted an extensive geological and
engineering evaluation of the property base, improved the operating efficiencies
of the properties, recompleted or reworked 58 wells, drilled 3 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.

Public Offering

      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 $8,500,000 will be used primarily for
development drilling.

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 Kenworthy, Jr.,
the company's President, has been active in various aspects of the oil and gas
business for over 20 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, a New York Stock Exchange listed company
which manufactures and sells road building equipment.


                                       1
<PAGE>

      Substantial Drilling and Exploitation Opportunities. We have a
substantial inventory of drilling and recompletion projects with an estimated
48 Bcfe of proved undeveloped reserves as of December 31, 2000. These
projects include ten recompletion projects and thirty 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, 2000 reserve report, the
pre-tax present value of the proved undeveloped reserves is $284 million with
anticipated future development costs of $13.5 million.

      Significant Inventory of Unproved Prospects. We have approximately 200
additional drilling locations in East Texas which we believe have potential in
the Pettit, Travis Peak and Cotton Valley formations at depths of 6,000 to
10,000 feet. 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. Approximately 21,885 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 2000 was 60% gas and 40% oil.
Proved reserves as of December 31, 2000 are 68% gas and 32% 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 to take advantage of the current high price levels.

      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.

      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 the high prices in the current market
and that we are subject to price declines if gas prices decline in the future.

      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 pricing policies and the possibility of supply
interruptions.


                                       2
<PAGE>

      For 1999, our largest purchasers included Teppco Crude and Koch Gateway
PipeLine which accounted for 75.4% and 19.3% of oil and natural gas sales,
respectively. For the year 2000, the same purchasers accounted for 83.4% and
41.4%, respectively, of oil and natural gas sales, respectively. 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.

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


                                       3
<PAGE>

relatively small amounts of liquid and solid waste that may be subject to
classification as hazardous substances under CERCLA.

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

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

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

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

      Marketing and Transportation. The interstate transportation and sale for
resale of natural gas is regulated by the Federal Energy Regulatory Commission
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 GMX.

      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.


                                       4
<PAGE>

Gas Gathering

      We have acquired, constructed and own gas gathering lines and compression
equipment for gathering and delivering of natural gas from our east Texas
properties. This gathering system currently consists of approximately 24 miles
of gathering lines that collect gas from approximately 18 wells, which accounted
for approximately 65% of our gas production from this area in 2000. 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.

Competition

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

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

Facilities

      As of March 15, 2001, we leased approximately 6,749 square feet in
Oklahoma City, Oklahoma for our corporate headquarters. The annual rental cost
is approximately $94,485.

Employees

      As of March 15, 2001, we had 14 full-time employees of which 4 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 meaning is 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.


                                       5
<PAGE>

      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 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.


                                       6
<PAGE>

      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.

      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.


                                       7
<PAGE>

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

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

      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:

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


                                       8
<PAGE>

      The following table sets forth certain information regarding our
activities in each of our principal areas as of December 31, 2000.

<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) ................     59,745          3,962        3,586        4,924     72,217
Percent of total proved reserves .......         83%             5%           5%           7%       100%
Gross producing wells ..................         58             64           29            7        158
Net producing wells ....................       35.4           20.3         12.4          5.6       73.7
Gross acreage ..........................     18,389         11,539        3,556        2,077     35,562
Net acreage ............................     17,068          4,120        2,300        1,888     25,377
Proved undeveloped reserves (MMcfe) ....     42,532            307        1,582        3,985     48,406
Estimated development costs ($000s) ....    $ 9,900        $   201      $   675      $ 2,210    $12,986
Proved undeveloped locations ...........         22              2            3            3         30

Year ended December 31, 2000 results:
Production (net) MMcfe) ................        706            219          134           99      1,158
Average net daily production (Mcfe) ....      1,934            600          367          271      3,172
</TABLE>

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

East Texas and Northwestern Louisiana

East Texas

      The East Texas properties are located in Harrison and Panola Counties,
Texas. These properties contain approximately 17,708 gross (16,540 net) acres
with rights covering the Travis Peak, Pettit, Glen Rose and Cotton Valley
formations. Our East Texas properties have 58.9 Bcfe of proved reserves or 82%
of our total proved reserves at December 31, 2000, of which 42.5 Bcfe is
classified as proved undeveloped.

      We have interests in 49 gross (31.1 net) producing wells in East Texas, of
which we operate 35. Average daily production net to our interest for 2000 was
1.4 MMcf of gas and 60 Bbls of oil. Production is primarily from the Betheny,
Blocker and Waskom Fields. The producing lives of these fields are generally 12
to 70 years. We have identified productive zones in the existing wells that are
currently behind pipe and thus are not currently producing. These zones can be
brought into production as existing reserves are depleted. The Blocker area
includes 15 gross (13.5 net) wells in Harrison County which produce gas that is
gathered, compressed and sold by Endeavor Pipeline, Inc., a subsidiary of GMX.
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 this area lies on Sabine Uplift just north of the Carthage Field. The area
has 28 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
42.5 Bcfe, frequently located at the intersection of multiple crossing reservoir
trends. We have successfully completed three new wells since December 31,
1999--the Bosh #1 and #2 and the J. Hancock #1 at depths ranging from 6,600 to
6,700 feet. These wells produce from multiple zones of the Pettit and Travis
Peak formations and confirmed the existence of additional proved undeveloped
reserves. We have completed mapping and evaluation of the Travis Peak and Pettit
formations and have identified 22 drilling locations with proved undeveloped
reserves in these


                                       9
<PAGE>

zones. It is likely that as these locations are drilled, we will be able to
identify still more such locations with proved undeveloped reserves.

      Recent third party drilling in the vicinity of our development acreage
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.

      The Cotton Valley formation at depths of 8,500 to 10,000 feet is also
present and productive on the entire East Texas property base. In 1998, we
farmed out four 80-acre checkerboard locations in one of our 640-acre gas units
to Andrew Alan Exploration which has since drilled two 10,000 feet successful
Cotton Valley producing wells. One, the Patterson #1, was drilled in less than
30 days at a cost of approximately $900,000 and has estimated reserves of 1.5
Bcf in the Cotton Valley formation. The well also has five other zones that
appear productive in the Travis Peak and Pettit formations now behind pipe. The
other well, the Christian #1, was also drilled and completed successfully with
initial production of 1,582 Mmcf per day.

      We are studying the deeper potential in the Cotton Valley formation on our
property block and the Patterson #1 well confirms our theory that the Cotton
Valley formation may be underdeveloped. Prior Cotton Valley wells on our
leasehold were all completed before 1983 and none of these wells tested the
entire zone. We believe current completion procedures and techniques have the
potential to increase ultimate reserve recovery. Completed well costs for Cotton
Valley wells range from $700,000 to $1,200,000 depending on completion methods.
Our acreage position offers the potential for 187 natural gas Cotton Valley
drilling locations. We plan to drill our first three wells containing proved
undeveloped reserves in the Pettit and/or Travis Peak formations to the deeper
Cotton Valley field to test this unproved zone more fully. If these wells are
successful, we may drill additional Cotton Valley wells. We commenced the
drilling of our first well in this area during the week of February 12, 2001.

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 9 gross (4.3 net) producing wells, 6 of which we operate.
Production is predominately oil. Louisiana proved reserves are .8 Bcfe and
represent approximately 1% of proved reserves as of December 31, 2000. Average
daily production net to our interest for 2000 was 19 Bbls of oil and 21 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 and Oklahoma Panhandle areas are located in the Hugoton
Embayment of Finney and Scott Counties in Kansas, and Texas County in Oklahoma.
These areas combined consist of approximately 11,539 gross (4,120 net) acres.
Our western Kansas and Oklahoma Panhandle properties have 3,962 MMcfe of proved
reserves or 5% of our total proved reserves at December 31, 2000. The Hugoton
Embayment is one of the largest gas fields on the North American Continent. We
have a total of 64 gross (20.3 net) producing wells as of December 31, 2000.
Substantially all of these wells penetrate multiple formations which have
additional development potential. Average daily production net to our interest
for 2000 was 240 Mcf of gas and 60 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.

      In the Western Kansas properties, our ownership comprises approximately
10,899 gross (3,823 net) acres. 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


                                       10
<PAGE>

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 307 MMcfe as of December 31, 2000. We are continuing to evaluate
these properties for further development potential.

      Our Oklahoma acreage is the Etta Niles lease, which totals approximately
640 gross (297 net) acres, and is in the Carthage NW Field in Texas County,
Oklahoma. Most of the gas production is from the Topeka limestone formation and
oil production is from the Morrow formation. The company operates 3 producing
wells and 1 saltwater disposal well with an average daily net production of 54
Mcf and 3 Bbls of oil for 2000.

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 5% of
our total proved reserves at December 31, 2000. Average daily production net to
our interests for 2000 was 180 Mcf of gas and 31 Bbls of oil.

      We have 29 gross (12.4 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 recently added new wells to this
unit, improved the injection system and added the ability to increase the water
injection volumes. Net production has recently increased 5 Bbls of oil per day
because of these improvements. We have identified 5 locations with proved
undeveloped reserves as of December 31, 2000 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 2,078 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 7% of our total proved reserves as of December 31, 2000.
Average daily production net to our interests for 2000 from our 7 gross (5.6
net) producing wells in this area was 72 Mcf of gas and 33 Bbls of oil.

      We have identified three locations with proved undeveloped reserves which
are planned for drilling in the near future. If successful, each well could
increase net production by approximately 55 Bbls of oil per day and 40 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, 2000, Sproule Associates Inc., our independent
petroleum engineers, estimates our proved reserves have increased to 72 Bcfe. An
estimated 24 Bcfe is expected to be produced from existing wells and another 48
Bcfe or 67% of the proved reserves, is classified as proved undeveloped. These
reserves were identified by geological and engineering evaluation of the data we
acquired with the properties, as well as by drilling three new wells and
reworking or recompleting 58 wells. All of our proved undeveloped reserves are
on locations which are adjacent to wells productive in the same formations. The
three development wells drilled based on this work have all been completed as
producers. As of December 31, 2000, we had interests in 158 producing wells, 130
of which we operate.

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


                                       11
<PAGE>

<TABLE>
<CAPTION>

                                                   Years Ended December 31,
                                               ------------------------------
                                                 1998       1999       2000
                                               --------   --------   --------
<S>                                               <C>        <C>       <C>
Proved Developed:
Gas (MMcf) .................................      8,597      9,194     15,352
Oil (MBbls) ................................        780      1,083      1,410
  Total (MMcfe) ............................     13,277     15,692     23,811
Proved Undeveloped:
Gas (MMcf) .................................      8,704     10,084     33,718
Oil (MBbls) ................................      1,084        564      2,448
  Total (MMcfe) ............................     15,208     13,468     48,406
Total Proved:
Gas (MMcf) .................................     17,301     19,278     49,070
Oil (MBbls) ................................      1,864      1,647      3,858
  Total (MMcfe) ............................     28,485     29,160     72,218

Estimated Future Net Revenues (1)($000s) ...   $ 35,429   $ 50,052   $492,310

Present Value(1)($000s) ....................   $ 25,275   $ 30,523   $284,161
</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 significant increase in proved reserves from December 31, 1999 to
December 31, 2000 resulted from the drilling and completion of three wells in
the Travis Peak and Pettit 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.

      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, 2000 were $26.42 per barrel for
oil and $9.90 per Mcf for gas, adjusted for quality, contractual agreements,
regional price variations and transportation and marketing fees. These period
end prices are higher than 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 $2,142,000 and $2,554,000 respectively, as of
December 31, 2000.

      Sproule Associates Inc., our independent reserve engineers, prepared the
estimates of proved reserves as of December 31, 2000. Estimates of proved
reserves for December 31, 1998 and 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.


                                       12
<PAGE>

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,
                                      ------------------------------------
                                         1998         1999         2000
                                      ----------   ----------   ----------
<S>                                   <C>          <C>          <C>
Property acquisition costs:
  Proved ..........................   $5,720,419   $  514,212   $  359,753
  Unproved ........................      615,803      199,860      335,259
Development costs .................      418,723      490,587    1,379,531
                                      ----------   ----------   ----------
  Total ...........................   $6,754,945   $1,204,659   $2,074,543
                                      ==========   ==========   ==========
</TABLE>

      We acquired, drilled or participated in the drilling of wells as set out
in the table below for the periods indicated. 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.

<TABLE>
<CAPTION>
                                      Year Ended December 31,
                            ---------------------------------------------
                                1998            1999             2000
                            -------------   -------------   -------------
                            Gross     Net   Gross     Net   Gross     Net
                            -----   -----   -----   -----   -----   -----
<S>                           <C>    <C>       <C>    <C>     <C>     <C>
Acquired wells:
  Gas ...................      65    31.8      --      --      --      --
  Oil ...................      90    39.3      --      --      --      --
                            -----   -----   -----   -----   -----   -----
        Total ...........     155    71.1      --      --      --      --
                            =====   =====   =====   =====   =====   =====

Development wells:
  Gas ...................      --      --       1      .8       1       1
  Oil ...................      --      --       1      .8      --      --
  Dry ...................      --      --      --      --      --      --
                            -----   -----   -----   -----   -----   -----
        Total ...........      --      --       2     1.6       1       1
                            =====   =====   =====   =====   =====   =====

Exploratory wells:
  Gas ...................      --      --      --      --      --      --
  Oil ...................      --      --      --      --      --      --
  Dry ...................      --      --      --      --      --      --
                            -----   -----   -----   -----   -----   -----
        Total ...........      --      --      --      --      --      --
                            =====   =====   =====   =====   =====   =====
</TABLE>


                                       13
<PAGE>

      The following table shows our developed and undeveloped oil and gas lease
and mineral acreage as of December 31, 2000. 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>
East Texas and Louisiana ..........   14,188   13,893    4,200    3,175
Western Kansas and Oklahoma .......   11,539    4,120       --       --
Central Kansas ....................    3,556    2,300       --       --
Southeast New Mexico ..............    1,760    1,571      317      317
                                      ------   ------   ------   ------
       Total ......................   31,045   21,885    4,517    3,492
                                      ======   ======   ======   ======
</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, 2000. Gross oil and gas wells include one well with multiple completions.
Wells with multiple completions are counted only once for purposes of the
following table.

Productive Wells

<TABLE>
<CAPTION>

                       Productive Wells
                       ----------------
Type of Well            Gross      Net
------------           ------    ------
<S>                        <C>     <C>
Gas ................       66      31.8
Oil ................       92      39.9
                       ------    ------
  Total ............      158      71.7
                       ======    ======
</TABLE>

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 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 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.

                                       14
<PAGE>

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

      On October 30, 2000, prior to the public offering, by unanimous written
consent shareholders owning 3,000,000 shares (adjusted for a stock split on
October 31, 2001), approved the GMX Resources Inc. Stock Option Plan and an
amendment to the Certificate of Incorporation increasing the authorized
shares of capital stock of the Corporation to 60,000,000 shares, divided into
50,000,000 shares of Common Stock, par value $.001 per share and 10,000,000
shares of Preferred Stock, par value $.001 per share.

                                     PART II

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

      We had no publicly traded securities for the fiscal year ending December
31, 2000. 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. As of March 29, 2001, we estimate
that there were approximately 1,200 beneficial owners of our common stock. The
high and low bid prices for our securities during the periods described below
were as follows:

<TABLE>
<CAPTION>

                                               High            Low
                                               ----            ---
<S>                                          <C>            <C>
February 12, 2001 to March 14, 2001
Units................................        $ 8.625        $ 7.1250
March 14, 2001 to March 28, 2001
Common Stock.........................        $ 5.125        $ 4.3125
Class A warrants.....................          1.500          1.0625
Class B warrants.....................          1.500          1.0000
</TABLE>

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.


                                       15
<PAGE>

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

Selected Financial Data

      The following table presents a summary of our financial information for
the periods indicated. It should be read in conjunction with our consolidated
financial statements and related notes and the discussion below.

<TABLE>
<CAPTION>
                                                               Years Ended December 31,
                                                     --------------------------------------------
                                                        1998(1)          1999            2000
                                                     ------------    ------------    ------------
<S>                                                  <C>             <C>             <C>
Statement of Operations Data:
Oil and gas sales ................................   $  1,794,513    $  2,122,770    $  4,153,934
Interest and other income ........................         33,404          38,915          37,378
                                                     ------------    ------------    ------------
  Total revenues .................................      1,827,917       2,161,685       4,191,312
                                                     ------------    ------------    ------------
Lease operations .................................        895,899         917,590       1,050,552
Production and severance taxes ...................        150,052         157,193         416,607
General and administrative .......................        226,313         368,824         578,641
Depreciation, depletion and amortization .........        426,562         424,509         420,488
Interest .........................................        426,709         498,199         664,713
                                                     ------------    ------------    ------------
  Total expenses .................................   $  2,125,535    $  2,366,315    $  3,131,001
                                                     ------------    ------------    ------------
Income (loss) before income taxes ................       (297,618)       (204,630)      1,060,311
Income taxes .....................................             --              --          52,000
                                                     ------------    ------------    ------------
Net income (loss) ................................   $   (297,618)   $   (204,630)   $  1,008,311
                                                     ============    ============    ============

Net income (loss) applicable to common shares ....   $   (478,368)   $   (373,193)   $    875,810
                                                     ============    ============    ============

Net income (loss) per share - basic ..............   $       (.22)   $       (.23)   $        .48
                                                     ============    ============    ============

Net income (loss) per share - diluted ............   $       (.22)   $       (.23)   $        .29
                                                     ============    ============    ============

Weighted average common shares - basic ...........      2,176,500       1,632,375       1,822,926
                                                     ============    ============    ============

Weighted average common shares - diluted .........      2,176,500       1,632,375       3,469,326
                                                     ============    ============    ============
Statement of Cash Flows Data:
Net cash provided by operating activities ........   $    197,231    $    618,759    $  1,394,168
Net cash used in investing activities ............     (6,720,450)       (685,060)     (2,177,335)
Net cash provided by financing activities ........      6,633,001         491,724         277,997

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

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


                                       16
<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
                                                                         --------   --------   --------
<S>                                                                      <C>        <C>        <C>
Production:
Oil production (MBbls) ...............................................         75         71         75
Natural gas production (MMcf) ........................................        442        443        719
Equivalent production (MMcfe) ........................................        892        869       1158

Average Sales Price:
Oil price (per Bbl) ..................................................   $  12.67   $  16.73   $  21.33 (1)
Natural gas price (per Mcf) ..........................................       1.91       2.09       3.57
                                                                         --------   --------   --------
Average sales price (per Mcfe) .......................................   $   2.01   $   2.43   $   3.59

Operating and Overhead Costs (per Mcfe):
Lease operating expenses .............................................   $   1.00   $   1.06   $    .91
Production and severance taxes .......................................        .17        .18        .36
General and administrative ...........................................        .25        .42        .50
                                                                         --------   --------   --------
      Total ..........................................................   $   1.42   $   1.66   $   1.77
                                                                         ========   ========   ========
Cash Operating Margin (per Mcfe) .....................................   $    .59   $    .77   $   1.82

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

Estimated Net Proved Reserves (as of the respective period-end):
Natural gas (Bcf) ....................................................       17.3       19.3       49.1
Oil (MMbls) ..........................................................        1.9        1.6        3.9
Total (Bcfe) .........................................................       28.7       29.2       72.5
Reserve Life (in years)(2) ...........................................        9.1       14.1       15.8
Estimated Future Net Revenues ($MM)(2)(3) ............................       33.4       50.1      492.3
Present Value ($MM)(2)(3) ............................................       25.3       30.5      284.2
</TABLE>

-----------------------------
(1)   Net of results of crude oil hedging activities in 2000 which reduced the
      average oil price in 2000 by $8.91 per Bbl.

(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".


                                       17
<PAGE>

Results of Operations--Year Ended December 31, 2000 Compared to Year Ended
December 31, 1999

      Oil and Gas Sales. Oil and gas sales in the year of 2000 increased 96%
to $4,153,934 compared to the year of 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 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 by $596,970. Production of natural gas also increased.
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 the year of 2000
resulted from new production and the reworking of certain wells.

      Lease Operations. Lease operations expense increased $132,962 in the year
of 2000 to $1,050,552, a 14% 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 $.91 per Mcfe
in 2000 compared to $1.06 per Mcfe for 1999. This decrease resulted from an
increase in production.

      Production and Severance Taxes. Production and severance taxes increased
165% to $416,607 in the year of 2000 compared to $157,193 in the year of 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 the year 2000, down 1%
from the year of 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 the year 2000 was $578,641 compared to $368,824 for the year of 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.

      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.

                                       18
<PAGE>

Results of Operations for the Year Ended December 31, 1999 Compared to Year
Ended December 31, 1998

      Oil and Gas Sales. Oil and gas sales in the year ended December 31, 1999
increased 18.3% to $2,122,770 compared to the year ended December 31, 1998,
primarily due to increased prices for oil and gas. The average price per barrel
of oil and mcf of gas received in 1999 was $16.73 and $2.09, respectively,
compared to $12.67 and $1.91 in 1998. Production of oil decreased slightly and
natural gas increased slightly. Oil production for 1999 decreased 5% to 71 Mbbl
compared to 75 Mbbl barrels for the prior year. Gas production increased to 443
MMcf compared to 442 MMcf for an increase of 0.2%.

      Lease Operations. Lease operations expense increased $21,691 in 1999 to
$917,590, a 2% increase compared to 1998. Lease operations expense on an
equivalent unit of production basis was $1.06 per Mcfe in 1999 compared to $1.00
per Mcfe for 1998. The increased 1999 expense resulted from initial costs to
improve the equipment and performance of certain wells.

      Production and Severance Taxes. Production and severance taxes increased
5% to $157,193 in 1999 compared to $150,052 in 1998. 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 decreased $2,053 to $424,509 in 1999. The oil and gas
depreciation, depletion and amortization rate per equivalent unit of
production was $0.43 per Mcfe in 1999, the same as in 1998.

      Interest. Interest expense for the year ended December 31, 1999 was
$498,199 compared to $426,709 for the year ended December 31, 1998. This
increase is primarily attributable to higher average long term debt balances
outstanding during 1999 as well as an increase in interest rates.

      General and Administrative Expense. General and administrative expense for
1999 was $368,824 compared to $226,313 for 1998. This increase of $142,511 was
the result of an increase in salaries of $94,653 along with a decrease in
reimbursements from third party working interest owners of $73,112. These
increased expenses were partially offset by a decrease in legal and professional
expense from 1998 to 1999 of $25,254. The salaries increase from 1998 to 1999
was due primarily to an executive salary increase of $103,000 which was reduced
by a decrease in operations salaries of $8,347 due to a decrease in personnel.
The decrease in reimbursements resulted from a reduction in overhead rates
charged to third party working interest owners. General and administrative
expense per equivalent unit of production was $0.42 per Mcfe for 1999 compared
to $0.25 per Mcfe for the prior year.

      Income Taxes. No income tax benefit was recognized as the company has
not previously generated taxable income and has not met the requirements
under accounting principles generally accepted in the United States of
America to recognize a tax benefit.

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. We have relied
heavily upon 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. These proceeds
will be used primarily for development drilling.


                                       19
<PAGE>

Cash Flow--Year Ended December 31, 2000 Compared to Year Ended December 31, 1999

      In the year ended December 31, 2000 and 1999, we spent $2,177,335 and
$685,060, respectively, in oil and gas acquisitions and development
activities. These investments were funded for the year of 2000 by existing
cash resources of $1,394,168 in net cash provided by operations and $277,997
provided by financing activities, primarily borrowings. EBITDA in the year of
2000 was $2,145,512 compared to $718,078 in the year of 1999, an increase of
199%. 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.

Cash Flow--1999 Compared to 1998

      In 1999 we expended $685,060 in investing activities compared to
$6,720,450 in 1998. The 1998 amount included our initial purchase of oil and
gas properties and equipment for $5,702,907. The 1999 year also 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 $197,231 in 1998, 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 $6,633,001 in 1998, including
$1,000,000 from our initial capitalization and $5,642,348 from net long-term
borrowings.

      EBITDA in 1999 was $718,078 compared to $555,653 in 1998, 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 the credit facility is the lesser of the Borrowing Base or the
amount of the Commitment. As of March 15, 2001, our Borrowing Base was $6.8
million and which will reduce by $105,000 per month until the maturity date
of May 1, 2003. Borrowings bear interest at the prime rate plus 1 /2 %. 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. We have made the required principal reductions since
December 1, 2000 out of cash flow from operations. 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 income plus depreciation, depletion
            and amortization plus interest expense divided by quarterly
            principal reduction requirements plus interest.
      -     Require a minimum tangible net worth of not less than $1.5 million,
            plus 75% of net income or other increases in equity after September
            30, 2000.
      -     Prohibit any liens or any other debt in excess of $100,000.


                                       20
<PAGE>

      -     Prohibit sales of assets more than $100,000.
      -     Prohibit payment of dividends or repurchases of stock.
      -     Prohibit mergers or consolidations with other entities.
      -     Prohibit material changes in management.

      We are in compliance with all of these covenants as of March 15, 2001. We
do not expect any of these covenants to materially restrict our activities
because our financial condition has been significantly improved as a result of
the receipt of the proceeds of our initial public offering. As of
December 31, 2000 we were not in compliance with the debt covenants requiring
a minimum adjusted current ratio, primarily as a result of paying costs of
the Company's February equity offering. A waiver was received for this
noncompliance on March 22, 2001.

      The credit facility is guaranteed by Messrs. Kenworthy, Jr. and Kenworthy,
Sr. The amount of their guarantees is limited to a maximum of $1 million each.

      At February 28, 2001, we had borrowed $6.8 million under the credit
facility, leaving no availability for borrowings to fund development drilling
obligations based on the existing Borrowing Base. If our drilling program is
successful and commodity prices remain at current levels, we expect our
Borrowing Base will increase and thereby provide additional sources of funds for
our planned capital expenditures.

      In connection with the execution of the credit facility, we entered into a
price swap agreement to hedge 5,000 barrels per month of oil production for the
first six months of 2001 at a fixed price of $29.10 per bbl. Based upon the
lenders' subsequent removal of the oil price hedging requirement, the Company
settled the oil price swap agreement on December 20, 2000 and received $76,334.

Shareholder Loans

      Prior to the closing of the 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. These loans are secured by undeveloped oil and
gas properties. Also in 2000, Ken L. Kenworthy, Jr. and Ken L. Kenworthy, Sr.
loaned the company an additional $230,000 to fund the company's repurchase of
outstanding preferred stock from an unrelated party. This loan bore interest at
a rate which approximated prime and was repaid on October 31, 2000, with an
advance under our revolving credit facility.

      At December 31, 2000, we had a deficit working capital balance of
$(1,359,587) and a current ratio--current assets as a ratio of current
liabilities--of .5 to 1. Excluding shareholder loans and the current portion of
long-term debt, we had a positive working capital balance of $328,000. Total
long-term debt outstanding at December 31, 2000 was $7.6 million.

Drilling Advances

      In 1999 we entered into a development agreement with Tara Energy
Partnerships ("Tara"), an unrelated third party, relating to the development of
two wells in east Texas. Tara acquired an 85% working interest in the wells and
advanced its estimated share of drilling and completion costs for these wells.
After Tara has received the return of its investment from oil and gas revenues
or other repayments, the company is entitled to a reversionary interest in the
wells. The size of the reversionary interest decreases based on the amount of
time it takes Tara to achieve payout. In October, 2000, we borrowed $544,000
under our credit facility to pay to Tara to cause payout to occur and increased
our working interest in the wells by 64% to 79%. The increase in interest had a
Present Value of proved reserves as of December 31, 2000 of approximately
$796,000. We may enter into similar arrangements in the future in order to
finance the development of wells.


                                       21
<PAGE>

Commitments and Capital Expenditures

      Other than obligations under our long-term debt, our commitments for
capital expenditures relate to planned development of oil and gas properties. We
do not enter into drilling or development commitments until such time as a
source of funding for such commitments is known to be available, either through
drilling advances, internal cash flow, additional funding under our bank credit
facility or working capital.

      We plan to drill up to 30 wells with proved undeveloped reserves of 72
Bcfe with an estimated capital cost of approximately $13.5 million prior to
December 31, 2001. We also plan to spend additional amounts to test deeper
unproved zones in some of these same wells at additional cost which we estimate
to be as much as $1.5 million for the initial three wells. If these wells are
successful, we will likely continue to drill these deeper wells and incur
additional costs. We expect to use internal cash flows or proceeds from
borrowings under our credit facility in addition to the proceeds from our
initial public offering for this purpose. The actual wells, costs and timing may
vary depending on drilling results, equipment availability, commodity prices and
other factors. However, a number of factors affect drilling and our plans may
change.

Hedging

      We have entered into, and expect to periodically enter into, financial
hedging 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 hedges when we believe forward market conditions
are relatively favorable, but we do not expect to hedge at any time more than
50% of our total production. Realized gains or losses from the settlement of
these financial hedging activities are recognized in oil and gas sales when the
associated production occurs. The gains and losses realized as a result of these
hedging activities are substantially offset in the cash market when the hedged
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 2000 from $29.24 to $21.33 per Bbl. These
swaps expired on December 31, 2000. For the first six months of 2001, we have
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. As noted above, we
settled an oil price swap agreement covering the first six months of 2001 on
December 20 for a gain of $76,334 which will be amortized into income during
2001 over the original term of the oil price swap agreement.

Impact of Recently Issued Accounting Standards Not Yet Adopted

      In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133") and in June 2000 issued SFAS
138, which amended certain provisions of SFAS 133. SFAS 133, as amended,
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities. It requires the recognition of all derivatives as either
assets or liabilities in the statement of financial position and measurement
of those instruments at fair value. If certain conditions are met, a
derivative may be specifically designated as a hedge. The accounting for
changes in the fair value of a derivative (that is gains and losses) depends
on the intended use of the derivative and whether it qualifies as a hedge.
The company adopted the provisions of SFAS 133, as amended, on January 1,
2001. The Company recorded a liability and a corresponding reduction in
stockholders' equity (net of deferred income tax benefit) equal to the fair
value of the derivative financial instruments. As of December 31, 2000, the
fair value was a liability of $187,800.

                                       22
<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

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.

We have limited operating history.

      We were organized in 1998 and have been in operation for less than three
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.


                                       23
<PAGE>

The loss of our President or other key personnel could adversely affect us.

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

We are managed by the members of a single family, giving them influence and
control in corporate transactions and their interests may differ from those of
other shareholders.

      Our executive officers consist of Ken L. Kenworthy, Jr., his father, 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 currently have, 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.

      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.

Rapid growth may place significant demands on our resources.

      We expect significant expansion of our operations. Our anticipated future
growth will place a significant demand on our managerial, operational and
financial resources due to:

      -     the need to manage relationships with various strategic partners and
            other third parties;
      -     difficulties in hiring and retaining skilled personnel necessary to
            support our business;
      -     the need to train and manage a growing employee base; and
      -     pressures for the continued development of our financial and
            information management systems.

      If we have not made adequate allowances for the costs and risks associated
with this expansion or if our systems, procedures or controls are not adequate
to support our operations, our business could be harmed.


                                       24
<PAGE>

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. will beneficially own
approximately 45% and 23%, 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 existence of outstanding warrants may impair our abilities to raise capital.

      There are 1,250,000 shares of our common stock issuable upon exercise of
the Class A warrants at a price of $9.00 per share if exercised before March 12,
2002 and $12.00 per share if exercised thereafter. These Class A warrants will
be exercisable to purchase common stock that would represent 23% of the common
stock outstanding following such exercise, assuming no other change in our
outstanding common stock. There are an additional 1,250,000 shares of our common
stock issuable upon exercise of the Class B warrants at a price of $10.00 per
share. These Class B warrants will be exercisable to purchase common stock that
would represent 19% of the common stock outstanding following such exercise,
assuming the Class A warrants are fully exercised and no other change in our
outstanding common stock. During the life of the warrants, the holders are given
an opportunity to profit from a rise in the market price of our common stock
with a resulting dilution in the interest of the other shareholders. Our ability
to obtain additional financing during the period the warrants are outstanding
may be adversely affected and the existence of the warrants may have an effect
on the price of our common stock. The holders of the warrants may be expected to
exercise them at a time when we would, in all likelihood, be able to obtain any
needed capital by a new offering of securities on terms more favorable than
those provided by the warrants.

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 1999, we received gas and oil prices at the wellhead ranging from
$0.91 to $2.91 per Mcf and $10.50 to $25.35 per Bbl. In 2000, we received gas
and oil prices ranging from $1.44 to $5.99 per Mcf and $23.73 to $33.89 per Bbl.
Oil and gas prices in 2000 have reached their highest level in the last several
years and we cannot assure you that they will remain at these levels. 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


                                       25
<PAGE>

      -     overall economic conditions.

We may encounter difficulty in obtaining equipment and services.

      Recent increased oil and gas drilling activity in the regions in which we
own properties has resulted in increased demand for drilling rigs, other
oilfield equipment, personnel and other services. We may experience increased
costs or shortages or unavailability of drilling rigs, drill pipe and other
material and other services used in oil and gas drilling. Such unavailability
could 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.

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.


                                       26
<PAGE>

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 such as the cold weather occurring in the fourth
            quarter of 2000 which caused some of our wells to be shut in for a
            few days;
      -     compliance with governmental requirements; and
      -     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. 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.


                                       27
<PAGE>

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.

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.


                                       28
<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

      On October 10, 2000, we terminated Wright & McAfee and elected to engage
KPMG LLP to audit our financial statements as of December 31, 1999 and for the
year then ended due to KPMG's more extensive experience with publicly-held
companies. Wright & McAfee's report on our financial statements for the year
ended December 31, 1998 did not contain an adverse opinion or disclaimer of
opinion and was not modified as to uncertainty, audit scope or accounting
principles. There were no disagreements with Wright & McAfee on any matter of
accounting principles or practices, financial statement disclosure or auditing
scope or procedure for the year ended December 31, 1998 and through October 10,
2000. The decision to change accountants was approved by the board of directors.

                                    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 2001 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,
2000.

Item 10. EXECUTIVE COMPENSATION

      The information required under item 10 will be contained in the proxy
statement for the 2001 Annual Meeting of Shareholders and is incorporated herein
by reference.

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 2001 Annual Meeting of Shareholders and is incorporated herein
by reference.

Item 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS


                                       29
<PAGE>

      The information required under item 12 will be contained in the proxy
statement for the 2001 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
      with the corresponding Exhibit Number contained in our Registration
      Statement on Form SB-2, file No. 333-49328.

      Exhibit
      No.                            Description of Exhibit
      -------     --------------------------------------------------------------

      3.1         Amended and Restated Certificate of Incorporation of GMX
                  RESOURCES INC.
      3.2         Bylaws of GMX RESOURCES INC.
      4.1         Warrant Agreement with form of Warrant
      4.2         Form of Underwriters' Warrant
      4.3         Form of Lock-up Agreement
      10.1*       Letter Agreement between GMX and Jon Stromberg relating to
                  issuance of 6,754 shares of GMX common stock
      10.2*       Stock Option Plan, as amended
      10.3        Secured Revolving Credit Agreement dated October 31, 2000 with
                  Local Oklahoma Bank, N.A.
      10.4        Letter Agreement to purchase Series B Preferred Stock
      10.5        Form of Director Indemnification Agreement
      10.6        Promissory Notes to Ken L. Kenworthy, Jr.
      10.7        Development Agreement with Tara Energy Partnership
      10.8        Form of Promotional Share Escrow Agreement

      *           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.


                                       30
<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: March 29, 2001                   By: /s/ Ken L. Kenworthy, Jr.
                                            ---------------------------------
                                            Ken L. Kenworthy, Jr., President

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

        Signatures                   Title                     Date

/s/ Ken L. Kenworthy, Jr.    President and Director       March 29, 2001
--------------------------                                --------------
Ken L. Kenworthy, Jr.


/s/ Ken Kenworthy, Sr.       Executive Vice President,    March 29, 2001
-------------------------    Chief Financial Officer      --------------
Ken Kenworthy, Sr.           and Director


/s/ Paul Malloy              Director                     March 29, 2001
-------------------------                                 --------------
Paul Malloy


/s/ T. J. Boismier           Director                     March 29, 2001
-------------------------                                 --------------
T. J. Boismier


                                       31
<PAGE>

                          INDEX TO FINANCIAL STATEMENTS

Independent Auditors' Report                                                 F-2

Consolidated Balance Sheets, December 31, 1999 and 2000                      F-3

Consolidated Statements of Operations,
         Years Ended December 31, 1999 and 2000                              F-4

Consolidated Statements of Changes in Shareholders' Equity,
         Years Ended December 31, 1999 and 2000                              F-5

Consolidated Statements of Cash Flows,
         Years Ended December 31, 1999 and 2000                              F-6

Notes to Financial Statements                                                F-7


                                      F-1
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

The Board of Directors and Stockholders
GMX Resources Inc.:

We have audited the accompanying consolidated balance sheets of GMX Resources
Inc. and subsidiaries as of December 31, 1999 and 2000 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, 1999 and 2000 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.


                                                 KPMG LLP

Oklahoma City, Oklahoma
March 23, 2001


                                      F-2
<PAGE>

                               GMX Resources Inc.
                           Consolidated Balance Sheets
                           December 31, 1999 and 2000

<TABLE>
<CAPTION>
                                                                                    1999            2000
                                                                                ------------    ------------
<S>                                                                             <C>             <C>
                                     ASSETS
CURRENT ASSETS:
       Cash                                                                     $    535,213    $     30,043
       Accounts receivable--interest owners                                          115,121         117,289
       Accounts receivable--oil and gas revenues                                     622,420         945,388
       Inventories                                                                    84,460          86,312
       Prepaid expenses                                                               16,819          19,673
                                                                                ------------    ------------
                 Total current assets                                              1,374,033       1,198,705
                                                                                ------------    ------------
OIL AND GAS PROPERTIES, AT COST, BASED ON THE FULL COST METHOD OF
   ACCOUNTING FOR OIL AND GAS PROPERTIES                                           7,897,087       9,971,628
       Less accumulated depreciation, depletion, and amortization                   (756,297)     (1,108,938)
                                                                                ------------    ------------
                                                                                   7,140,790       8,862,690
                                                                                ------------    ------------

OTHER PROPERTY AND EQUIPMENT                                                         489,026         600,822
       Less accumulated depreciation                                                 (91,261)       (154,321)
                                                                                ------------    ------------
                                                                                     397,765         446,501
                                                                                ------------    ------------

OTHER ASSETS                                                                          60,575         462,386
                                                                                ------------    ------------

                 TOTAL ASSETS                                                   $  8,973,163    $ 10,970,282
                                                                                ============    ============
                      LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
       Notes payable to Shareholder                                             $    200,000    $         --
       Accounts payable                                                              511,011         579,137
       Accrued expenses                                                               39,055          58,054
       Accrued interest                                                               54,144          65,215
       Revenue distributions payable                                                 524,611         595,888
       Drilling advances                                                             220,785              --
       Current portion of long-term debt                                              71,480       1,261,364
                                                                                ------------    ------------
                 Total current liabilities                                         1,621,086       2,559,658

LONG-TERM DEBT, LESS CURRENT PORTION                                               6,110,333       6,312,500

OTHER LIABILITIES                                                                    124,261         146,331

DEFERRED INCOME TAXES                                                                     --          52,000

SHAREHOLDERS' EQUITY:
       Preferred stock, par value $.01 per share, 500,000 shares authorized:
            Series A, 150,000 shares issued, and 100,000 shares outstanding
                 as of December 31, 1999.
                 No shares outstanding as of December 31, 2000                         1,500              --
            Series B, 22,000 shares issued and outstanding as of December 31,
                 1999.
                 No shares outstanding as of December 31, 2000                           220              --
       Common stock, par value $.001 per share--authorized 50,000,000 shares;
            issued 2,176,500 shares in 1999 and 3,000,000 in 2000;
            outstanding 1,451,000 shares in 1999 and 3,000,000 in 2000                 2,177           3,000
       Additional paid-in capital                                                  2,042,712       1,390,730
       Retained earnings (accumulated deficit)                                      (502,248)        506,063
       Treasury Stock:
            Common--725,500 shares at cost                                          (213,439)             --
            Preferred Series A--50,000 shares at cost                               (213,439)             --
                                                                                ------------    ------------
                 Total Shareholders' Equity                                        1,117,483       1,899,793
                                                                                ------------    ------------

                 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                     $  8,973,163    $ 10,970,282
                                                                                ============    ============
</TABLE>

See accompanying notes to consolidated financial statements


                                       F-3
<PAGE>

                               GMX Resources Inc.
                      Consolidated Statements of Operations
                     Years Ended December 31, 1999 and 2000

<TABLE>
<CAPTION>
                                                                  1999           2000
                                                              -----------    -----------
<S>                                                           <C>            <C>
REVENUE
        Oil and gas sales                                     $ 2,122,770    $ 4,153,934
        Interest income                                            15,108         23,123
        Other income                                               23,807         14,255
                                                              -----------    -----------
              Total revenue                                     2,161,685      4,191,312
                                                              -----------    -----------

EXPENSES
        Lease operations                                          917,590      1,050,552
        Production and severance taxes                            157,193        416,607
        Depreciation, depletion, and amortization                 424,509        420,488
        Interest                                                  498,199        664,713
        General and administrative                                368,824        578,641
                                                              -----------    -----------
              Total expenses                                    2,366,315      3,131,001
                                                              -----------    -----------

              Income (Loss) before income taxes                  (204,630)     1,060,311

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

              Net Income (Loss)                               $  (204,630)   $ 1,008,311
                                                              ===========    ===========

              Net Income (Loss) Applicable to common shares   $  (373,193)   $   875,810
                                                              ===========    ===========

              EARNINGS (LOSS) PER SHARE--BASIC                $     (0.23)   $      0.48
                                                              ===========    ===========

              EARNINGS (LOSS) PER SHARE--DILUTED              $     (0.23)   $      0.29
                                                              ===========    ===========

              WEIGHTED AVERAGE COMMON SHARES--BASIC             1,632,375      1,822,926
                                                              ===========    ===========

              WEIGHTED AVERAGE COMMON SHARES--DILUTED           1,632,375      3,469,326
                                                              ===========    ===========
</TABLE>

See accompanying notes to consolidated financial statements.


                                      F-4
<PAGE>

                               GMX Resources Inc.
           Consolidated Statements of Changes in Stockholders' Equity
                     Years Ended December 31, 1999 and 2000

<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, 1998                 2,176,500    $     2,177        150,000    $     1,500         22,000    $       220

Services rendered in exchange for stock             --             --             --             --             --             --
      (Stock issued in 2000)                        --
Purchase of treasury stock                          --             --             --             --             --             --
Net loss                                            --             --             --             --             --             --
                                           -----------    -----------    -----------    -----------    -----------    -----------

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)
Retiment of treasury stock                    (725,500)          (726)       (50,000)          (500)            --             --
Conversion of preferred stock, Series A      1,451,000          1,451       (100,000)        (1,000)            --             --
Net income                                          --             --             --             --             --             --
                                           -----------    -----------    -----------    -----------    -----------    -----------

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

<CAPTION>
                                                                      RETAINED
                                                      ADDITIONAL      EARNINGS                       TOTAL
                                                       PAID-IN     (ACCUMULATED)    TREASURY     SHAREHOLDERS'
                                                       CAPITAL        DEFICIT)        STOCK          EQUITY
                                                     -----------    -----------    -----------    -----------
<S>                                                  <C>            <C>            <C>            <C>
BALANCE AT DECEMBER 31, 1998                         $ 1,996,103    $  (297,618)   $        --    $ 1,702,382

Services rendered in exchange for stock                   46,609             --             --         46,609
      (Stock issued in 2000)
Purchase of treasury stock                                    --             --       (426,878)      (426,878)
Net loss                                                      --       (204,630)            --       (204,630)
                                                     -----------    -----------    -----------    -----------

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)
Retiment of treasury stock                              (425,652)            --        426,878             --
Conversion of preferred stock, Series A                     (451)            --             --             --
Net income                                                    --      1,008,311             --      1,008,311
                                                     -----------    -----------    -----------    -----------

BALANCE AT DECEMBER 31, 2000                         $ 1,390,730    $   506,063    $        --    $ 1,899,793
                                                     ===========    ===========    ===========    ===========
</TABLE>

See accompanying notes to consolidated financial statements.


                                      F-5
<PAGE>

                               GMX Resources Inc.
                      Consolidated Statements of Cash Flows
                     Years Ended December 31, 1999 and 2000

<TABLE>
<CAPTION>
                                                                            1999           2000
                                                                        -----------    -----------
<S>                                                                     <C>            <C>
CASH FLOWS DUE TO OPERATING ACTIVITIES
       Net income (loss)                                                $  (204,630)   $ 1,008,311
       Adjustments to reconcile net income (loss) to
            net cash provided by operating activities:
                 Depreciation, depletion, and amortization                  424,509        420,488
                 Deferred income taxes                                           --         52,000
                 (Gain) loss on sale of other property and equipment         (4,513)       (13,789)
                 Stock to be issued for consulting services                  46,609          4,000
                 Amortization of debt issuance costs                         11,965         61,457
                 Decrease (increase) in:
                      Accounts receivable                                  (244,412)      (325,136)
                      Inventory and prepaid expenses                        (39,915)        (4,706)
                 Increase (decrease) in:
                      Accounts payable                                      186,159         68,126
                      Accrued expenses and other liabilities                 28,029         52,140
                      Revenue distributions payable                         414,958         71,277
                                                                        -----------    -----------

                            Net cash provided by operating activities       618,759      1,394,168
                                                                        -----------    -----------

CASH FLOWS DUE TO INVESTING ACTIVITIES
       Purchase of oil and gas properties                                  (781,907)    (2,086,641)
       Purchase of property and equipment                                   (56,171)      (125,294)
       Proceeds from sale of oil and gas properties                         124,518         12,100
       Proceeds from sale of other property and equipment                    28,500         22,500
                                                                        -----------    -----------

                            Net cash used in investing activities          (685,060)    (2,177,335)
                                                                        -----------    -----------

CASH FLOWS DUE TO FINANCING ACTIVITIES
       Proceeds from borrowings                                             725,000      8,473,500
       Payments of debt issue costs                                         (34,396)       (15,000)
       Payments on debt                                                     (20,535)    (7,281,449)
       Retirement of preferred stock                                             --       (230,001)
       Purchase of treasury stock                                          (399,130)            --
       Other assets                                                              --       (448,268)
       Drilling advances                                                    220,785       (220,785)
                                                                        -----------    -----------

                            Net cash provided by financing activities       491,724        277,997
                                                                        -----------    -----------

Net increase (decrease) in cash                                             425,423       (505,170)

CASH AT BEGINNING OF YEAR                                                   109,790        535,213
                                                                        -----------    -----------

CASH AT END OF YEAR                                                     $   535,213    $    30,043
                                                                        ===========    ===========

NON-CASH INVESTING AND FINANCING ACTIVITIES
       Exchange of property and equipment for treasury stock            $   (18,409)   $        --
                                                                        ===========    ===========

CASH PAID FOR INTEREST                                                  $   470,867    $   614,327
                                                                        ===========    ===========
</TABLE>

See accompanying notes to consolidated financial statements.


                                      F-6
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 1999 AND 2000

NOTE A--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include the
accounts of GMX Resources Inc. (the "Company") 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.

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.

REVENUE RECOGNITION AND 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.


                                      F-7
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 1999 AND 2000

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 $57,529 and $59,715 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 1999 and 2000,
respectively.

INCOME TAXES: The Company accounts for income taxes using the asset and
liability method. Under the asset and liability method, deferred tax assets and
liabilities are recognized at the enacted tax rates for the future tax
consequences attributable to differences between the financial carrying amounts
of existing assets and liabilities and the respective tax bases and tax
operating losses and tax credit carryforwards. The effect on deferred tax assets
and liabilities of a change in tax rates is recognized in income in the period
that includes the enactment date.

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

The Company accounts 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 are recognized in oil and gas revenues when the
associated production occurs and the resulting cash flows are reported as cash
flows from operating activities. Gains and losses on hedging contracts that are
closed before the hedged production occurs are 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 is recognized currently to the extent the hedging
instrument has not offset changes in actual oil and gas prices.

The Company adopted the provisions of 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 $116,000 in accumulated
other comprehensive loss to recognize at fair value all derivatives that are
designated as cash-flow hedging financial instruments.

                                      F-8
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 1999 AND 2000

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.

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 price swap agreements.

NET EARNINGS PER COMMON SHARE: Basic earnings per share is computed by dividing
income available to common shareholders by the weighted average number of common
shares outstanding for the period. Diluted earnings per share reflect the
potential dilution that could occur if the Company's convertible preferred stock
were converted to common stock, net of preferred dividends associated with the
dilutive convertible preferred stock. The diluted loss per share calculation for
1999 produced results that were anti-dilutive. Therefore, the diluted loss per
share amount for 1999 reported in the accompanying Consolidated Statements of
Operations is the same as the basic loss per share amounts. The weighted average
dilutive shares not included in the 1999 period was 2,770,090. The weighted
average dilutive shares included in the 2000 period was 1,646,400.

STOCK OPTIONS: The Company applies the intrinsic value-based method of
accounting for its fixed plan stock options. 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.

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.


                                      F-9
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 1999 AND 2000

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.

NOTE B--PROPERTY AND EQUIPMENT

Property and equipment included the following:

<TABLE>
<CAPTION>
                                                                   December 31,
                                                           --------------------------
                                                              1999           2000
                                                           -----------    -----------
<S>                                                        <C>            <C>
Oil and gas properties:
   Subject to amortization                                 $ 7,176,877    $ 9,179,489
   Not subject to amortization:
      Acquired in 2000                                              --        335,259
      Acquired in 1999                                         199,860        188,379
      Acquired in 1998                                         520,350        268,501
   Accumulated depreciation, depletion, and amortization      (756,297)    (1,108,938)
                                                           -----------    -----------
       Net oil and gas properties                            7,140,790      8,862,690
                                                           -----------    -----------
Other property and equipment                                   489,026        600,822
Less accumulated depreciation                                  (91,261)      (154,321)
                                                           -----------    -----------
       Net other property and equipment                        397,765        446,501
                                                           -----------    -----------
         Property and equipment, net of accumulated
            depreciation, depletion, and amortization      $ 7,538,555    $ 9,309,191
                                                           ===========    ===========
</TABLE>

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

<TABLE>
<CAPTION>

                                                    For The Year Ended
                                                       December 31,
                                                   -------------------
                                                     1999       2000
                                                   --------   --------
<S>                                                <C>        <C>
Depreciation, depletion, and amortization of oil
   and gas properties                              $372,199   $352,641
Depreciation of other property and equipment         52,310     67,847
                                                   --------   --------
           Total                                   $424,509   $420,488
                                                   ========   ========
</TABLE>


                                      F-10
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 1999 AND 2000

NOTE C--LONG-TERM DEBT

<TABLE>
<CAPTION>

                                                 December 31,
                                          ---------------------------
                                              1999           2000
                                          -----------    -----------
<S>                                       <C>            <C>
Note payable to bank, maturity date of
January 31, 2001, bearing a variable
interest rate, (9.5% as of December 31,
1999), collateralized by producing oil
and gas properties                        $ 5,800,000

Note payable to bank, maturity date of
May 1, 2003, bearing a variable
interest rate, (10% as of December 31,
2000), collateralized by producing oil
and gas properties                                       $ 7,145,000

Notes payable to Shareholder, bearing
variable interest rates, (9.5% and
10.0%, as of December 31, 1999 and 2000,
respectively), collateralized by
unproved properties                           575,500        427,500

Other                                           6,813          1,364
                                          -----------    -----------
                                            6,381,813      7,573,864
Current portion - related parties           (200,000)            --
Current portion - unrelated parties           (71,480)    (1,261,364)
                                          -----------    -----------
                                          $ 6,110,333    $ 6,312,500
                                          ===========    ===========
</TABLE>

2000 Credit Facility

On October 31, 2000, the Company entered into a new secured credit facility,
which replaced the 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. The credit facility has a maturity date of May 1,
2003. 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.

The credit facility is personally guaranteed by the President and Executive
Vice-President. The amount of their guarantees is limited to a maximum of
$1,000,000 each.


                                      F-11
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 1999 AND 2000

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 the LIBOR
rate 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.

The estimated maturities of long-term debt (excluding the note payable to
shareholder in the amount of $427,500 that was paid in full after the Company's
February 2001 equity offering - see Note F) as of December 31, 2000 are as
follows:

<TABLE>

<S>                                               <C>
      2001                                        $1,261,364
      2002                                         1,260,000
      2003                                         4,625,000
                                                  ----------
      Total                                       $7,146,364
                                                  ==========
</TABLE>

NOTE D--INCOME TAXES

Intangible development costs are expensed for income tax reporting purposes,
whereas they are capitalized and amortized for financial statements purposes.
Lease and well equipment and other property and equipment is 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-12
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 1999 AND 2000

At December 31, 2000, the Company had the following carryforwards available to
reduce future income taxes:

<TABLE>

<S>                                               <C>
      Federal                                     $1,491,000
      State                                          879,000
      Statutory depletion                            660,000
</TABLE>

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, 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's deferred tax liability of $432,000 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 $509,000 was primarily the result of the
Company's net operating loss 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.

For the year ended December 31, 2000, the Company's effective income tax rate of
5% reflects the utilization of net operating loss carryforwards that previously
were subject to a valuation allowance and the effects of statutory depletion
deductions that are in excess of the Company's cost for income tax
determination.


                                      F-13
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 1999 AND 2000

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.

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, 2000.

Year Ending December 31:

<TABLE>

<S>                                                 <C>
          2001                                      $ 88,681
          2002                                        97,298
          2003                                       100,673
          2003                                        16,870
                                                    --------
          Total                                     $303,522
                                                    ========
</TABLE>

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

<TABLE>

<S>                                                  <C>
          1999                                       $42,299
          2000                                        59,630
</TABLE>

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) were to pay dividends
at $6.00 per share per year and also were cumulative. Series B could be redeemed
at the option of the Company. The redemption price was as follows:

<TABLE>

<S>                                               <C>
      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
</TABLE>


                                      F-14
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 1999 AND 2000

No shares were redeemed as of December 31, 1999. After December 31, 2001, the
shares are 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, 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 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 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 Plan. The exercise price of options granted under the 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.


                                      F-15
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 1999 AND 2000

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

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

NOTE G--OTHER RELATED PARTY TRANSACTIONS

The Company had an agreement to issue common stock in exchange for services
primarily performed in 1999 based on an agreement reached with an engineer in
February 1999. In February 2000, 98,000 shares were issued pursuant to this
agreement. Invoices subject to the agreement of $50,609 have been recorded as
equity.

NOTE H--MAJOR CUSTOMERS

Sales to individual customers constituting 10% or more of total oil and gas
sales for each of the years ended December 31, 1999 and 2000 were as follows:

<TABLE>

                                                          1999          2000
                                                          ----          ----
<S>                                                       <C>           <C>
      Teppco Crude                                        49.7%         32.2%
      Koch Gateway Pipeline                               10.3%         25.1%
</TABLE>

Management believes that the loss of any of the above customers would not have a
material impact on the Company's results of operations or its financial
position.


                                      F-16
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 1999 AND 2000

NOTE I--HEDGING ACTIVITIES

During 1999 and 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
1999 totaled $81,600 and 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 entered into a natural gas price swap that
initiated in January 2001 and is to expire in June 2001. The agreement
relates to 20,000 mmbtu per month whereby the Company will receive a fixed
price of $4.70 per mmbtu and pay the counterparty an index price.

The fair value of the financial instrument as of December 31, 1999 was a
liability of approximately $134,000. The fair value of the financial instrument
as of December 31, 2000 was a liability of approximately $187,800.

NOTE J--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 K--OIL AND GAS OPERATIONS

Capitalized costs related to the Company's oil and gas producing activities as
of December 31, 1999 and 2000 are:

<TABLE>
<CAPTION>

                                                         1999           2000
                                                     -----------    -----------
<S>                                                  <C>            <C>
Unproved properties                                  $   720,210    $   792,189
Producing properties                                   7,176,877      9,179,989
                                                     -----------    -----------
                                                       7,897,087      9,971,628
Less accumulated depreciation, depletion, and
amortization                                            (756,297)    (1,108,938)
                                                     -----------    -----------
           Net capitalized costs                     $ 7,140,790    $ 8,862,690
                                                     ===========    ===========
</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 represents the portion of the assets which have been
charged to expense.


                                      F-17
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 1999 AND 2000

Costs incurred in oil and gas property acquisitions, exploration, and
development activities in 1999 and 2000 are as follows:

<TABLE>
<CAPTION>

                                                      1999         2000
                                                   ----------   ----------
<S>                                                <C>          <C>
      Property acquisition costs - unproved        $  199,860   $  335,259
      Property acquisition costs - proved             514,212      359,753
      Development costs                               490,587    1,379,531
                                                   ----------   ----------
                                                   $1,204,659   $2,074,543
                                                   ==========   ==========
</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 1999 and 2000 includes revenues and
expenses associated directly with oil and gas producing activities.

<TABLE>
<CAPTION>

                                                        1999         2000
                                                     ----------   ----------
<S>                                                  <C>          <C>
      Oil and gas sales                              $2,122,770   $4,153,934
      Production costs                                1,074,783    1,467,359
      Depreciation, depletion and amortization          359,199      352,641
      Income tax expense                                     --      405,000
                                                     ----------   ----------
      Results of operations for oil and gas
           producing activities                      $  688,788   $1,928,934
                                                     ==========   ==========
</TABLE>

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

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


                                      F-18
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 1999 AND 2000

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,
1999 and 2000, 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, 1999
   Proved reserves, beginning of period                     1,864        17,301
        Extensions, discoveries, and other
           additions                                           66         2,219
        Production                                            (71)         (443)
        Sale of reserves in-place                             (20)           --
        Revisions of previous estimates                      (192)          201
                                                       ----------    ----------
        Proved reserves, end of period                      1,647        19,278
                                                       ==========    ==========
        Proved developed reserves:
            Beginning of period                               780         8,597
                                                       ==========    ==========
            End of period                                   1,083         9,194
                                                       ==========    ==========
December 31, 2000
   Proved reserves, beginning of period                     1,647        19,278
   Extensions, discoveries, and other additions             2,161        30,409
   Production                                                 (75)         (710)
   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
                                                       ==========    ==========
</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 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.


                                      F-19
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 1999 AND 2000

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,
                                                     1999            2000
                                                 ------------    ------------
                                                (In thousands)  (In thousands)
<S>                                              <C>             <C>
Future cash inflows                              $     78,630    $    587,789
Future production costs                               (22,482)        (82,013)
Future development costs                               (6,096)        (13,466)
Future income tax provisions                          (12,160)       (169,578)
                                                 ------------    ------------
     Net future cash inflows                           37,892         322,732
Less effect of a 10% discount factor                  (14,989)       (136,451)
                                                 ------------    ------------
     Standardized measure of discounted future
         net cash flows                          $     22,903    $    186,281
                                                 ============    ============
     Discount (at 10%) future net cash flows
         before income taxes                     $     30,523    $    284,161
                                                 ============    ============
</TABLE>

Oil and condensate prices were based on an equivalent base price of $26.83 per
barrel for benchmark posted West Texas Intermediate Crude Oil at closing on
December 31, 2000. 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 $26.42 per barrel. Natural gas prices were based on an equivalent base price
of $9.81 per million British thermal unit (mmbtu) for the composite Henry Hub
Spot Market benchmark price at closing on December 31, 2000. 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 $9.90 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. Subsequent to December 31,
2000, natural gas prices have decreased. The average price for February 2001 as
measured by the composite Henry Hub benchmark price was $5.74 per mmbtu.


                                      F-20
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 1999 AND 2000

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

<TABLE>
<CAPTION>
                                                             December 31,  December 31,
                                                                 1999          2000
                                                             ------------  ------------
<S>                                                            <C>          <C>
Standardized measure, beginning of year                        $  19,246    $   22,903
Sales of oil and gas, net of production costs                       (976)       (2,687)
Net changes in prices and production costs                         3,809        84,709
Extensions and discoveries, net of future development costs          422       166,091
Development costs that reduced future development costs              491           900
Revisions of quantity estimates                                   (1,250)        1,870
Sales of reserves in place                                           (46)           --
Accretion of discount                                              2,528         3,025
Net changes in income taxes                                       (1,321)      (90,530)
                                                              ----------    ----------

Standardized measure, end of year                              $  22,903    $  186,281
                                                              ==========    ==========
</TABLE>


                                      F-21