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

                                  FORM 10-KSB/A

[X]    ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
       ACT OF 1934
       For the fiscal year ended December 31, 2003

[_]    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.
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                 (Name of small business issuer in its charter)

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

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

(ISSUER'S TELEPHONE NUMBER) (405) 600-0711

SECURITIES REGISTERED UNDER SECTION 12(B) OF THE EXCHANGE ACT:
                                      NONE

SECURITIES REGISTERED UNDER SECTION 12(G) OF THE EXCHANGE ACT:
                    NAME OF EACH EXCHANGE ON WHICH REGISTERED

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

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

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

The issuer's revenue for the year ended December 31, 2003 was $5,388,794.

The aggregate market value of the voting and non-voting common equity (excluding
warrants) held by non-affiliates on April 13, 2004 was $17.8 million. This
amount was computed using closing price of the issuer's common stock on April
13, 2004 on the NASDAQ National Market.

As of April 13, 2004, the issuer had outstanding a total of 6,775,000 shares of
its $0.001 par value Common Stock.

DOCUMENTS INCORPORATED BY REFERENCE - None

Transitional Small Business Disclosure Format (Check one):   Yes  [_]  No [X]
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                               GMX RESOURCES INC.
                                   FORM 10-KSB
                                TABLE OF CONTENTS

                                                                            PAGE


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

          General.............................................................1
          2001 Equity Offerings...............................................1
          Drilling Contract...................................................1
          2002 and 2003 Activities............................................2
          2003 Year End and 2004 Developments.................................2
          Business Strategy...................................................4
          Marketing...........................................................4
          Regulation..........................................................5
          Gas Gathering.......................................................8
          Competition.........................................................8
          Facilities..........................................................8
          Employees...........................................................8
          Certain Technical Terms.............................................9
Item 2.   PROPERTIES.........................................................12

          Reserves...........................................................15
          Costs Incurred and Acquisition and Drilling Results................16
          Productive Well Summary............................................18
Item 3.   LEGAL PROCEEDINGS..................................................18

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


                                     PART II

Item 5.   MARKET FOR COMMON EQUITY RELATED STOCKHOLDER
          MATTERS, AND SMALL BUSINESS ISSUER PURCHASES OF
          EQUITY SECURITIES..................................................19

          Common Stock Information...........................................19
          Recent Sales of Unregistered Securities............................20
          Purchases of Equity Securities by the Small Business Issuer........20
Item 6.   MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF
          OPERATION..........................................................20

          Selected Financial Data............................................20
          Summary Operating and Reserve Data.................................21
          Critical Accounting Policies.......................................22
          Results of Operations for the Year Ended December 31, 2003
          Compared to Year Ended December 31, 2002...........................24
          Results of Operations for the Year Ended December 31, 2002
          Compared to Year Ended December 31, 2001...........................25
          Capital Resources and Liquidity....................................26

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          Cash Flow--Year Ended December 31, 2003 Compared to Year
          Ended December 31, 2002............................................26
          Cash Flow--Year Ended December 31, 2002 Compared to Year
          Ended December 31, 2001............................................27
          Credit Facility....................................................27
          Subordinated Notes.................................................28
          Common Stock Private Placement.....................................28
          Working Capital....................................................28
          Commitments and Capital Expenditures...............................29
          Liquidity and Financing Considerations.............................29
          Price Risk Management..............................................29
          Impact of Recently Issued Accounting Standards Not Yet Adopted.....30
          Forward-Looking Statements.........................................31
          Risk Factors Related to GMX........................................32
          Risks Related to the Oil and Gas Industry..........................34
Item 7.   FINANCIAL STATEMENTS...............................................39

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

Item 8A.  CONTROLS AND PROCEDURES............................................39


                                    PART III

Item 9.   DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL
          PERSONS; COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE
          ACT................................................................40

          Significant Employees..............................................41
          Consultant.........................................................41
          Terms..............................................................41
          Section 16(a) Beneficial Ownership Reporting Compliance............42
          Audit Committee Matters............................................42
          Code of Ethics.....................................................42
Item 10.  EXECUTIVE COMPENSATION.............................................42

          Summary Compensation Table.........................................42
          Compensation of Directors..........................................43
Item 11.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
          OWNERSHIP AND MANAGEMENT...........................................43

          Equity Compensation Plan Information...............................45
Item 12.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.....................45

Item 13.  EXHIBITS AND REPORTS ON FORM 8-K...................................45

Item 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES.............................45

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                                     PART I

ITEM 1. BUSINESS

GENERAL

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

2001 EQUITY OFFERINGS

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

            On June 22, 2001, our common stock became eligible for trading on
the NASDAQ National Market. In July 2001, we completed a secondary public
offering of 2,300,000 shares of common stock at an offering price of $5.50 per
share. This firm commitment offering was also underwritten by Paulson Investment
Company, Inc., and I-Bankers Securities Incorporated. The proceeds of the
offering, net of underwriters' fees and other expenses, were approximately $11.3
million, and were used primarily for the development drilling of oil and gas
wells in 2001 and early 2002.

DRILLING CONTRACT

            On May 29, 2001, we entered into a drilling contract with Nabors
Drilling USA LP ("Nabors"), obligating us to use two 10,000 foot drilling rigs
and crews on a continuous basis for a period of two years at a cost of $14,000
per day per rig. The day rate was payable regardless of whether we were actually
using the rigs. Our payment obligations were secured by standby letters of
credit in the aggregate amount of $1,000,000, $500,000 per rig, issued by our
lender under our credit facility in favor of Nabors.

            On December 13, 2001, we terminated the contracts and filed a
lawsuit in the United States District Court for the Western District of Oklahoma
against Nabors alleging that Nabors

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made misrepresentations intended to induce us to enter into the drilling
contracts as well as alleging that Nabors breached those contracts by providing
substandard drilling services. Nabors drew the full $1,000,000 on the letters of
credit and counterclaimed for approximately $10,000,000 alleged to be owed for
an early termination fee and unpaid invoices. On December 20, 2002, we received
a jury verdict in our favor in our lawsuit against Nabors in the United States
District Court for the Western District of Oklahoma after a five day trial. As a
result of the jury verdict, the Company had no liability to Nabors on its claim
for approximately $10 million in contract termination damages. In March 2003,
Nabors filed a notice of appeal of the jury verdict. In May 2003, GMX and Nabors
settled the lawsuit. Nabors dismissed its appeal and both parties executed
mutual releases of all claims.

2002 AND 2003 ACTIVITIES

            Due to liquidity issues from the uncertainties associated with the
Nabors litigation, as well as technical defaults under our credit facility, we
curtailed all drilling and development activities in 2002 and 2003 and
implemented a number of actions to reduce overhead costs. In addition, in July
2002, we engaged Petroleum Place Advisors ("Petroleum Place") to assist us as a
financial advisor in connection with possible property sales and other
alternatives. Effective as of September 30, 2002, we completed the sale of all
of our oil and gas properties in Kansas which had proved reserves of 9,571
Mmcfe. Net proceeds of the sales were $3.6 million, of which $3.3 million was
applied to our bank debt. We also solicited bids through Petroleum Place for
either a purchase of our east Texas properties or a joint venture to develop
these properties. This process concluded in December 2002. After our success in
the trial court in the Nabors litigation, we elected to evaluate other strategic
alternatives rather than accept proposals made at that time.

            Since the settlement of the Nabors litigation in May of 2003, we
have continued to actively seek additional sources of financing from outside
sources including potential industry partners or private sources of debt and
equity financing. As a result of the maturity of our bank credit facility in May
of 2003, we were in default under this facility until August 31, 2003 when we
negotiated an amended agreement and extended our then existing credit line of
$7.2 million to mature on March 1, 2004. Even though the Company was able to
negotiate extensions in its bank credit facility, during much of 2002 and 2003,
the Company had significant accounts payable over 90 days which it was able to
gradually reduce over this time frame.

2003 YEAR END AND 2004 DEVELOPMENTS

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

            On December 29, 2003, we executed a definitive participation
agreement with Penn Virginia Oil & Gas Corporation ("PVOG"), a wholly-owned
subsidiary of Penn Virginia Corporation , a publicly-held company traded on the
New York Stock Exchange under the symbol PVA, for the joint development of our
Cotton Valley, Travis Peak and Pettit prospects located in East Texas. This
agreement designates agreed geographic areas which surround and encompass
distinct portions of our acreage positions in East Texas defined as "Phases."
PVOG began drilling on February 11, 2004 in "Phase I," which includes
approximately 4,289 net acres comprising a portion of our proved undeveloped
acreage. GMX will have a 20% carried interest

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in the first five wells drilled in Phase I and will have a right to participate
for 30% of additional Phase I wells. Phase II, which includes approximately
5,200 net acres of our acreage, may commence after completion of Phase I, five
carried wells and no earlier than January 1, 2005 and no later than July 1,
2005. In Phase II, GMX will have a 20% carried interest in the first four wells
and will have a right to participate for 50% of additional drilling in Phase II.
GMX received approximately $950,000 in acreage and drilling location cost
reimbursement which was applied to reduce current liabilities. For additional
information concerning the PVOG agreement, see "Item 2 - Properties."

            On January 16, 2004, we completed a private placement of $1 million
of 11% senior subordinated notes maturing in 2007 with annual principal
installments prior to maturity of $100,000 and five year warrants to purchase
175,000 shares of common stock for $1.50 per share. The proceeds of this
placement are being used for completion of wells with proved developed
non-producing reserves, other production enhancement, further reduction in
current liabilities, placement fees and transaction costs associated with the
transaction.

            In addition on April 5, 2004, the Company closed a private placement
of 200,000 shares of common stock for $1,000,000 with an investor. Proceeds of
the transaction will be used for general corporate purposes. We are also
actively pursuing other sources of external financing through private equity
offerings and expect that additional placements may occur.

            Effective March 1, 2004, we reached an agreement with our bank
lender to extend our existing credit line of $6,260,000 to mature on September
1, 2004. The Company will continue to make monthly payments of $90,000 in
principal payments plus interest at New York prime plus 1% until the maturity
date. On April 14, 2004, our bank offered to extend the maturity of the line to
September 1, 2005, if we use the $1 million common stock sale proceeds to repay
the 11% subordinated notes. We are considering the proposal, but in the
meantime, we are evaluating several other proposals from other bank lenders to
maximize our flexibility for refinancing the credit facility and increasing our
borrowing base. As of April 14, 2004, we have received three term sheets from
these prospective lenders. See "Management's Discussion and Analysis on Plan of
Operation."

            As a result of the PVOG and private placement transactions, the
Company's liquidity has been substantially improved and as of April 6, 2004, the
Company has sufficient working capital to meet its accounts payable obligations
on a timely basis. The Company's cash flow in 2004 is expected to be sufficient
to meet its current obligations as they become due as well as to finance some
limited recompletion and production enhancement activities.

            Since year end 2003 through April 6, 2004, PVOG has drilled and
completed one well under our participation agreement in which we have a 20%
carried interest and has commenced the drilling of a second carried interest
well. We have conducted recompletion or production enhancement operations on
three wells in which we have 100% working interest. These wells have been
recompleted in the Pettit, Travis Peak and Cotton Valley formations. They were
producing approximately 1,500 mcfpd as of April 6, 2004, but this production
rate is expected to decline in the normal course of production.

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BUSINESS STRATEGY

            If we are able to obtain financing, our strategy will be to create
additional value from our East Texas property base through development of
quality proved undeveloped properties and exploitation activities focused on
adding proved reserves from the inventory of probable and possible drilling
locations. We have the following resources:

            EXPERIENCED MANAGEMENT. The Company's founders have experience in
finding, exploiting, developing and operating reserves and companies. Ken L.
Kenworthy, Jr., the Company's President, has been active in various aspects of
the oil and gas business for over 29 years. He was formerly Chairman and Chief
Executive Officer of OEXCO, Inc. ("OEXCO"), an Oklahoma City based privately
held oil and gas company. He founded OEXCO in 1980 and successfully managed it
until 1995 when it was sold for approximately $13 million. During this 15 year
period, OEXCO operated approximately 300 wells. Ken L. Kenworthy, Sr. also has
extensive financial experience with private and public businesses, including
experience as Chief Financial Officer of CMI Corporation, formerly a New York
Stock Exchange listed company which manufactured and sold road building
equipment.

            SUBSTANTIAL DRILLING AND EXPLOITATION OPPORTUNITIES. We have a
substantial inventory of drilling and recompletion projects with an estimated 31
Bcfe of proved undeveloped reserves as of December 31, 2003. These projects
include 27 recompletion projects and 52 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, 2003 reserve report, the pre-tax present
value of the proved reserves is $71 million with anticipated future development
costs of $44.5 million.

            SIGNIFICANT INVENTORY OF UNPROVED PROSPECTS. We have approximately
200 additional drilling locations in East Texas which we believe have potential
in the Pettit, Travis Peak and Cotton Valley formations at depths of 6,000 to
10,000 feet. Approximately 13,954 acres of our leasehold position is held by
production, so we do not have rental payments and drilling targets on those
leases can be held and drilled in order of priority without concern about lease
expiration.

            EMPHASIS ON GAS RESERVES. Production for 2003 was 82% gas and 18%
oil. Proved reserves as of December 31, 2003 are 85% gas and 15% oil. We intend
to emphasize acquisition and development of gas reserves due to the long term
outlook for gas demand, but will continue to maintain a portion of our reserves
in oil.

            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.

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

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

            CRUDE OIL. Oil produced from our properties will be sold at the
prevailing field price to one or more of a number of unaffiliated purchasers in
the area. Generally, purchase contracts for the sale of oil are cancelable on
30-days notice. The price paid by these purchasers is generally an established
or "posted" price that is offered to all producers. During the last several
years prices paid for crude oil have fluctuated substantially. Future oil prices
are difficult to predict due to the impact of worldwide economic trends, coupled
with supply and demand variables, and such non-economic factors as the impact of
political considerations on Organization of the Petroleum Exporting Countries
("OPEC") pricing policies and the possibility of supply interruptions.

            Our largest purchasers include TEPPCO Crude and Crosstex Pipeline
Company, which accounts for 99% and 83% of oil and natural gas sales currently.
We do not believe that the loss of any of our purchasers would have a material
adverse affect on our operations. None of our gas or oil sales contracts have a
term of more than one year.

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

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produce oil and gas and the number of wells we may drill. All statements in this
report about the number of locations or wells reflect current laws and
regulations.

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

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

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

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

            The Resource Conservation and Recovery Act of 1976, as amended
("RCRA"), is the principal federal statute governing the treatment, storage and
disposal of hazardous wastes. RCRA imposes stringent operating requirements, and
liability for failure to meet such requirements, on a person who is either a
"generator" or "transporter" of hazardous waste or an "owner" or "operator" of a
hazardous waste treatment, storage or disposal facility. At present, RCRA
includes a statutory exemption that allows most oil and natural gas exploration
and production waste to be classified as nonhazardous waste. A similar exemption
is contained in

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

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

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

GAS GATHERING

            We have acquired, constructed and own, through a wholly-owned
subsidiary, Endeavor, gas gathering lines and compression equipment for
gathering and delivering of natural gas from our east Texas properties. As of
December 31, 2003, this gathering system consisted of approximately 34 miles of
gathering lines that collect gas from approximately 40 wells, which accounted
for approximately 95% of our gas production from this area in both 2003 and
2002. This system enables us to improve the control over our production and
enhances our ability to obtain access to pipelines for ultimate sale of our gas.
We only gather gas from wells in which we own an interest. Remaining gas is
gathered by unrelated third parties. Endeavor also serves as first purchaser of
gas from wells for which we are the operator. See "Business-Marketing."

COMPETITION

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

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

FACILITIES

            As of December 31, 2003, we leased approximately 6,749 square feet
in Oklahoma City, Oklahoma for our corporate headquarters. The annual rental
cost is approximately $82,000.

EMPLOYEES

            As of December 31, 2003, we had eight full-time employees of which
three are management and the balance are clerical or technical employees. This
is down from 11 full-time employees at December 31, 2002 and 18 at December 31,
2001. We also use five independent

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contractors to assist in field operations. We believe our relations with our
employees are satisfactory. Our employees are not covered by a collective
bargaining agreement.

CERTAIN TECHNICAL TERMS

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

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

            BCF. Billion cubic feet.

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

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

            BBTU. Billion Btus.

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

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

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

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

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

            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.

                                        9
<PAGE>

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

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

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

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

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

            MBBLS. Thousand barrels.

            MBTU. Thousand Btus.

            MCF. Thousand cubic feet.

            MCFPD. Thousand cubic feet per day.

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

            MMBBLS. Million barrels.

            MMBTU. Million Btus.

            MMCF. Million cubic feet.

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

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

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

            NYMEX. New York Merchantile Exchange.

            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.

                                       10
<PAGE>

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

            PROVED RESERVES. The estimated quantities of crude oil, natural gas
and natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions; i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not escalations
based upon future conditions.

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

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

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

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

            UNDEVELOPED ACREAGE. Lease acreage on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and gas regardless of whether such acreage contains proved
reserves.

            WATERFLOOD. A secondary recovery operation in which water is
injected into the producing formation in order to maintain reservoir pressure
and force oil toward and into the producing wells.

                                       11
<PAGE>

            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

            As of December 31, 2003, we owned properties in the following
productive basins in the United States:

               o    The Sabine Uplift in East Texas and Louisiana;

               o    The Tatum Basin in Southeast New Mexico.

            The following table sets forth certain information regarding our
activities in each of these areas as of December 31, 2003.
<TABLE><CAPTION>
                                                                   EAST TEXAS   SOUTHEAST
                                                                       AND         NEW
                                                                    LOUISIANA     MEXICO      TOTAL
                                                                    ---------     ------      -----
            PROPERTY STATISTICS:
            --------------------
<S>                                                                   <C>          <C>        <C>
            Proved reserves (MMcfe)                                   51,681       1,286      52,967
            Percent of total proved reserves                             98%          2%        100%
            Gross producing wells                                         48           7          55
            Net producing wells                                         36.1         5.6        41.7
            Gross acreage                                             18,847       2,077      20,924
            Net acreage                                               10,120       1,821      11,941
            Proved developed nonproducing reserves (MMcfe)            21,156         530      21,686
            Proved undeveloped reserves (MMcfe)                       30,527         755      31,282
            Estimated total future development costs ($000s)        $ 44,058      $  500    $ 44,558
            Estimated 2004 development costs ($000s)                   6,183         500       6,683
            Proved undeveloped locations                                  51           1          52

            YEAR ENDED DECEMBER 31, 2003 RESULTS:
            Production (net MMcfe)                                     1,051          73       1,124
            Average net daily production (Mcfe)                        2,880         194       3,074
</TABLE>

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

EAST TEXAS

            The East Texas properties are located in Harrison and Panola
Counties, Texas. These properties contain approximately 18,167 gross (9,764 net)
acres with rights covering the Travis Peak, Pettit, Glen Rose and Cotton Valley
formations. Our East Texas properties have 51.2 Bcfe

                                       12
<PAGE>

of proved reserves or 97% of our total proved reserves at December 31, 2003, of
which 30.5 Bcfe is classified as proved undeveloped.

            We have interests in 42 gross (33.7 net) producing wells in East
Texas, of which we operate 37. Average daily production net to our interest for
2003 was 2,434 Mcf of gas and 68 Bbls of oil. Production is primarily from the
Betheny, Blocker and Waskom Fields. The producing lives of these fields are
generally 12 to 70 years. We have identified productive zones in the existing
wells that are currently behind pipe and thus are not currently producing. These
zones can be brought into production as existing reserves are depleted. The
Blocker and Betheny areas include 36 gross (30.7 net) wells in Harrison County
which produce gas that is gathered, compressed and sold by Endeavor. Gas sold
from the Blocker area has a high MMBtu content which results in a net price
above NYMEX average daily Henry Hub natural gas price. Oil is sold separately at
a slight premium to the average NYMEX Sweet Crude Cushing price, inclusive of
deductions. Most of the planned development will be added to existing gathering
systems under comparable contracts.

            The undeveloped acreage in these areas lies on Sabine Uplift just
north of the Carthage Field. The area has 29 producing reservoirs at depths from
3,000 to 10,000 feet. The reservoir trends are similar to river channels and
beach barrier bars and are generally substantial in length and sometimes width.
These features occur in more than one producing horizon and we give first
priority to drilling locations where a single well can drill through two or more
producing zones. This increases the reserves recoverable through a single
wellbore. We believe the natural gas development opportunities on this property
base are substantial and abundant. Our proved developed non-producing and proved
undeveloped reserves are significant in this region consisting of 41.4 Bcfe,
frequently located at the intersection of multiple crossing reservoir trends.
Each well generally penetrates multiple potentially productive formations,
including the Pettit, Travis Peak and Cotton Valley.

            In 2001, GMX successfully drilled and completed ten wells on its
East Texas property. Most of these were dual completions, each well having two
or more separate producing reservoirs in either the Pettit, Travis Peak or
Cotton Valley geological formations from 6,000 to 10,000 feet deep. The dual
completions have the same effect as drilling 20 separate single zone wells. We
did not drill any wells in 2002 or 2003 due to a lack of financial resources.
Annual production volumes of oil and natural gas net to the Company's interest
for 2003 was 1,005 Mmcfe compared with production in 2002 of 1,858 Mmcfe, a
year-over-year decrease of 46%.

            For 2004, GMX initially plans to participate in ten wells in East
Texas during 2004 and recomplete seven wells, subject to availability of capital
resources. The pace of future development of this property will depend on the
pace of PVOG's activity under our joint participation agreement described below,
availability of capital, future drilling results, the general economic
conditions of the energy industry and, on the price the Company receives for the
natural gas and crude oil produced. There is a potential for up to 400 locations
of Cotton Valley wells in our East Texas acreage assuming an ultimate well
density of two wells in each 80 acre tract.

            On December 29, 2003, we executed a definitive participation
agreement with PVOG for the joint development of our Cotton Valley, Travis Peak
and Pettit prospects located in East Texas. This agreement designates agreed
geographic areas which surround and encompass

                                       13
<PAGE>

distinct portions of our acreage positions in East Texas defined as "Phases."
PVOG began drilling on February 11, 2004 in "Phase I," which includes
approximately 5,082 net acres comprising a portion of our proved undeveloped
acreage. GMX will have a 20% carried interest in the first five (5) wells
drilled in Phase I and will have a right to participate for 30% of additional
Phase I wells. Phase II, which includes approximately 5,670 net acres of our
acreage, may commence after completion of Phase I, five (5) carried wells and no
earlier than January 1, 2005 and no later than July 1, 2005. In Phase II, GMX
will have a 20% carried interest in the first four (4) wells and will have a
right to participate for 50% of additional drilling in Phase II. GMX received
approximately $950,000 in acreage and drilling location cost reimbursement which
was applied to reduce current liabilities.

            The PVOG agreement also designates areas of mutual interest ("AMIs")
in which GMX and Penn Virginia agree that they will have rights to jointly
acquire acreage. The Phase I AMI consists of 20,500acres in which GMX and PVOG
have agreed to share future acreage acquisitions on a 70% PVOG/30% GMX basis.
The Phase II AMI consists of 22,400acres and a 50% PVOG/50% GMX sharing ratio.
The Phase III AMI consists of 15,360 acres and is an area surrounding GMX's
existing wells. GMX has granted to PVOG a right of first refusal on any sale of
acreage in Phase III and PVOG is restricted from acquiring acreage in Phase III
until one year after termination of the participation agreement, unless GMX no
longer owns acreage in Phase III.

            PVOG has publicly annouced plans to drill eight wells in 2004 on the
Phase I acreage.

            At December 31, 2003, Sproule Associates, Inc., our independent
reserve engineering firm, assigned a total of 10.6 Bcfe of proved reserves to
the completed East Texas wells, 10.1 Bcfe to our proved developed non-producing
wells, and 30.5 Bcfe of proved undeveloped reserves to our 51 proved undeveloped
locations in East Texas.

NORTHWESTERN 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 six gross (2.4 net) producing wells, three of which we
operate. Production is predominately oil. Louisiana proved reserves are .5 Bcfe
and represent approximately 1% of proved reserves as of December 31, 2003.
Average daily production net to our interest for 2003 was 3 Bbls of oil and 22
Mcf of gas. We are in the process of evaluation of additional behind pipe and
undeveloped reserves in the region. The wells are producing around a piercement
saltdome which has produced numerous structural traps for oil.

SOUTHEAST NEW MEXICO

            Our Southeast New Mexico properties are located in Lea and Roosevelt
counties and consist of approximately 2,077 gross (1,821 net) acres. The acreage
lies on the northwestern edge of the Midland Basin, defined as the Tatum Basin.
Existing production is from three zones--the Bough C, Abo and San Andreas--at
depths ranging from 9,500 to 10,000 feet. Proved reserves in Southeast New
Mexico are 1.3 Bcfc and represent 2% of our total proved reserves as of December
31, 2003. Average daily production net to our interests for 2003 from our 7
gross (5.6 net) producing wells in this area was 53 Mcf of gas and 24 Bbls of
oil.

                                       14
<PAGE>

            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, 2003, Sproule Associates Inc. estimates our
proved reserves are 53 Bcfe. An estimated 22 Bcfe is expected to be produced
from existing wells and another 31 Bcfe or 59% of the proved reserves, is
classified as proved undeveloped. All of our proved undeveloped reserves are on
locations which are adjacent to wells productive in the same formations. As of
December 31, 2003, we had interests in 59 producing wells, 47 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.


                                                  YEARS ENDED DECEMBER 31,

                                                2001        2002        2003
                                                ----        ----        ----
PROVED DEVELOPED:
Gas (MMcf)                                     21,932      16,501      18,277
Oil (MBbls)                                     1,018         604         568
                        Total (MMcfe)          28,040      20,125      21,685

PROVED UNDEVELOPED:
Gas (MMcf)                                     46,679      40,181      26,752
Oil (MBbls)                                     2,844       1,060         755
                        Total (MMcfe)          63,740      46,541      31,282

TOTAL PROVED:
Gas (MMcf)                                     68,611      56,683      45,029
Oil (MBbls)                                     3,862       1,663       1,323
                        Total (MMcfe)          91,781      66,663      52,967

ESTIMATED FUTURE NET REVENUES (1)($000S)     $155,678    $186,336    $178,348

PRESENT VALUE(1)($000S)                      $ 70,952    $ 80,614    $ 71,192

-------------------
(1)  The prices used in calculating Estimated Future Net Revenues and the
     Present Value are determined using prices as of period end. Estimated
     Future Net Revenues and the Present Value give no effect to federal or
     state income taxes attributable to estimated future net revenues. The
     standardized measure of discounted future net cash flows as of 2001, 2002
     and 2003 was $48,524,000, $54,312,000, and $47,975,000respectively.

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

                                       15
<PAGE>

            The quantity and value of our proved undeveloped reserves is
dependent upon our ability to fund the associated development costs which were a
total of an estimated $44.5 million as of December 31, 2003, of which $7.2
million is scheduled in the reserve report to be expended in 2004. We do not
currently have the resources to fund these development costs and, accordingly,
there is substantial uncertainty about our ability to develop these proved
undeveloped reserves in the time frame estimated in the reserve report. If we
enter into additional joint ventures or other arrangements to fund some or all
of the development costs, our interests in the reserves would likely be reduced,
as they were in connection with the PVOG participation agreement. Accordingly,
there is no assurance we will be able to realize the value of our estimated
proved undeveloped reserves.

            Estimates of the quantity and value of our proved undeveloped
reserves is also dependent upon the amount of interest that we expect to own in
these reserves. In connection with the PVOG participation agreement executed in
December of 2003, PVOG's rights in Phase II of the agreement are contingent upon
PVOG's successful completion of Phase I. Our year end reserve estimates assumes
that PVOG will earn its rights in the Phase II acreage for a limited number of
Phase II wells. Our reserve estimates would be increased if PVOG does not earn
rights in Phase II and would be decreased if PVOG fully participates in the
Phase II potential drilling.

            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, 2003 were $32.52 per
barrel for oil and $6.189 per Mmbtu for gas, adjusted for quality, contractual
agreements, regional price variations and transportation and marketing fees.
These period end prices are not necessarily the prices we expect to receive for
our production but are required to be used for disclosure purposes by the SEC.
We estimate that if all other factors (including the estimated quantities of
economically recoverable reserves) were held constant, a $1.00 per Bbl change in
oil prices and a $.10 per Mcf change in gas prices from those used in
calculating the Present Value would change such Present Value by $500,000 and
$1,000,000 , respectively, as of December 31, 2003.

            Sproule Associates, Inc., our independent reserve engineers,
prepared the estimates of proved reserves as of December 31, 2003, 2002 and
2001.

            No estimates of our proved reserves comparable to those included in
this report have been included in reports to any federal agency other than the
Securities and Exchange Commission.

COSTS INCURRED AND ACQUISITION AND DRILLING RESULTS

            The following table shows certain information regarding the costs
incurred by us in our acquisition and development activities during the periods
indicated. We have not incurred any exploration costs.

                                       16
<PAGE>

                                           YEAR ENDED DECEMBER 31,
                                ---------------------------------------------
                                     2001            2002             2003
PROPERTY ACQUISITION COSTS:
            Proved              $  2,382,548    $    120,157    $      57,565
            Unproved               2,488,614          84,672            5,212
DEVELOPMENT COSTS                 19,270,480       2,812,876          173,840
                                ------------    ------------    -------------
            Total               $ 24,141,642    $  3,017,705    $     236,617
                                ============    ============    =============

            We drilled or participated in the drilling of wells as set out in
the table below for the periods indicated. The table was completed based upon
the date drilling commenced. We did not acquire any wells or conduct any
exploratory drilling during these periods. You should not consider the results
of prior acquisition and drilling activities as necessarily indicative of future
performance, nor should you assume that there is necessarily any correlation
between the number of productive wells acquired or drilled and the oil and gas
reserves generated by those wells.


                                            YEAR ENDED DECEMBER 31,
                                 ---------------------------------------------
                                      2001            2002            2003
                                 ------------    ------------    ------------
DEVELOPMENT WELLS:               Gross    Net    Gross    Net    Gross    Net

            Gas                    10      10      --     --       --     --
            Oil                     1      .5      --     --       --     --
            Dry                    --     --       --     --       --     --
                                 ----    ----     ----   ----     ----   ----
                        Total      11    10.5      --     --       --     --
                                 ====    ====     ====   ====     ====   ====

            The following table shows our developed and undeveloped oil and gas
lease and mineral acreage as of December 31, 2003. Excluded is acreage in which
our interest is limited to royalty, overriding royalty and other similar
interests.


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

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

                                       17
<PAGE>

PRODUCTIVE WELL SUMMARY

            The following table shows our ownership in productive wells as of
December 31, 2003 Gross oil and gas wells include one well with multiple
completions. Wells with multiple completions are counted only once for purposes
of the following table.

                                          PRODUCTIVE WELLS
                                          ----------------
               TYPE OF WELL               GROSS       NET
               ------------               -----       ---
               Gas                          34       27.9
               Oil                          21       13.8
                                          -----     ------
                           Total            55       41.7
                                          =====     ======

ITEM 3. LEGAL PROCEEDINGS

            None.

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

            The annual meeting of shareholders was held on December 15, 2003,
and the four incumbent directors were elected for the ensuing year with the
following votes.

                                                                    WITHHELD
                   NAME                          VOTES FOR          AUTHORITY
                   ----                          ---------          ---------

            Ken L. Kenworthy, Jr.                6,365,873           48,309
            Ken L. Kenworthy, Sr.                6,365,873           48,309
            T. J. Boismier                       6,365,873           48,309
            Steven Craig                         6,365,873           48,309






                                       18
<PAGE>
                                     PART II

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

COMMON STOCK INFORMATION

            The high and low bid prices for our Common Stock and Class A
Warrants as listed on the NASDAQ National Market as applicable during the
periods described below were as follows:
                                                           HIGH          LOW
                                                           ----          ---
            JANUARY 1, 2002 TO MARCH 31, 2002
            ---------------------------------
            Common Stock                                 $ 4.65        $ 2.40
            Class A warrants                               1.85          0.60

            APRIL 1, 2002 TO JUNE 30, 2002
            ------------------------------
            Common Stock                                 $ 3.80        $ 2.06
            Class A warrants                               0.76          0.32

            JULY 1, 2002 TO SEPTEMBER 30, 2002
            ----------------------------------
            Common Stock                                 $ 2.60        $ 1.50
            Class A warrants                               0.32          0.04

            OCTOBER 1, 2002 TO DECEMBER 31, 2002
            ------------------------------------
            Common Stock                                 $ 2.45        $ 0.89
            Class A warrants                               0.22          0.01

            JANUARY 1, 2003 TO MARCH 31, 2003
            ---------------------------------
            Common Stock                                 $ 1.96        $ 1.06
            Class A Warrants                               0.50          0.05

            APRIL 1, 2003 TO JUNE 30, 2003
            ------------------------------
            Common Stock                                 $ 2.14        $ 0.63
            Class A Warrants                               0.49          0.04

            JULY 1, 2003 TO SEPTEMBER 30, 2003
            ----------------------------------
            Common Stock                                 $ 2.23        $ 1.33
            Class A Warrants                               0.19          0.09

            OCTOBER 1, 2003 TO DECEMBER 31, 2003
            ------------------------------------
            Common Stock                                 $ 4.50        $ 1.30
            Class A Warrants                               0.72          0.09


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

            As of March 15, 2004, there were 33 record owners of our Common
Stock and approximately 1,660 beneficial owners.

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

            We have never declared or paid any cash dividends on our shares of
common stock and do not anticipate paying any cash dividends on our shares of
common stock in the foreseeable future. Currently, we intend to retain any
future earnings for use in the operation and expansion of our business. Any
future decision to pay cash dividends will be at the discretion of our board of
directors and will be dependent upon our financial condition, results of
operations, capital
                                       19
<PAGE>

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.

RECENT SALES OF UNREGISTERED SECURITIES

            None during the fourth quarter of 2004.

PURCHASES OF EQUITY SECURITIES BY THE SMALL BUSINESS ISSUER

            None

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

SELECTED FINANCIAL DATA

            The following table presents a summary of our financial information
for the periods indicated. It should be read in conjunction with our
consolidated financial statements and related notes (beginning on page F-1 at
the end of this report) and the discussion below.
















                                       20
<PAGE>
<TABLE><CAPTION>

                                                                                    YEARS ENDED DECEMBER 31,
                                                                          --------------------------------------------
                                                                              2001            2002            2003
                                                                          ------------    ------------    ------------
<S>                                                                      <C>             <C>             <C>
STATEMENT OF OPERATIONS DATA:
Oil and gas sales                                                         $  5,898,003    $  5,970,792    $  5,367,370
Interest and other income                                                      554,296          17,550          21,424
                                                                          ------------    ------------    ------------
                        Total revenues                                       6,452,299       5,988,342       5,388,794
                                                                          ------------    ------------    ------------
Lease operations                                                             1,604,559       1,324,481         827,513
Production and severance taxes                                                 338,637         382,826         384,069
General and administrative                                                   1,855,736       2,577,388       1,578,865
Depreciation, depletion and amortization                                     1,026,498       1,901,976       1,549,678
Accretion expense on asset retirement obligations                                 --              --            22,521
Interest                                                                       359,118         510,472         439,313
                                                                          ------------    ------------    ------------
                        Total expenses                                    $  5,184,548    $  6,697,142    $  4,801,959
                                                                          ------------    ------------    ------------
Income (loss) before income taxes                                            1,267,751        (708,800)        586,835
Income tax expense (benefit)                                                   211,000        (263,000)           --
                                                                          ------------    ------------    ------------
Net income before cumulative effect of a change in accounting principle   $  1,056,751    $   (445,800)   $    586,835
                                                                          ============    ============    ============

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

Net income (loss) applicable to common shares                             $  1,056,751    $   (445,800)   $    535,001
                                                                          ============    ============    ============

Net income (loss) per share - before cumulative effect                    $        .21    $       (.07)   $        .09
                                                                          ============    ============    ============

Cumulative effect                                                         $       --      $       --      $        .01
                                                                          ============    ============    ============

Net income (loss) per share - basic and diluted                           $        .20    $       (.07)   $        .08
                                                                          ============    ============    ============

Weighted average common shares - basic                                       5,148,493       6,550,000       6,560,000
                                                                          ============    ============    ============

Weighted average common shares - diluted                                     5,179,693       6,550,000       6,560,000
                                                                          ============    ============    ============
STATEMENT OF CASH FLOWS DATA:
Net cash provided by (used in) operating activities                       $  8,016,600    $ (2,547,639)   $  1,014,290
Net cash provided by (used in) investing activities                        (26,700,785)      1,267,831         464,315
Net cash provided by (used in) financing activities                         18,657,867       1,820,000      (1,385,000)

BALANCE SHEET DATA (AT END OF PERIOD):
Oil and gas properties, net                                               $ 32,148,615    $ 29,359,309    $ 27,660,317
Total assets                                                                36,719,674      33,319,432      31,501,206
Long-term debt, including current portion                                    6,280,000       8,100,000       6,690,000
Shareholders' equity                                                        22,474,563      21,607,463      22,618,565
</TABLE>


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.

                                       21
<PAGE>
<TABLE><CAPTION>
                                                                                  YEARS ENDED DECEMBER 31,
                                                                         ----------------------------------------
                                                                            2001           2002           2003
                                                                         ----------     ----------     ----------
<S>                                                                     <C>            <C>            <C>
PRODUCTION:
Oil production (MBbls)                                                           81             70             35
Natural gas production (MMcf)                                                 1,294          1,639            917
Equivalent production (MMcfe)                                                 1,778          2,059          1,124

AVERAGE SALES PRICE:
Oil price (per Bbl)                                                      $     24.86(1) $    23.48(1)  $     30.41
Natural gas price (per Mcf)                                                    3.01(1)        3.03(1)        4.73(1)
                                                                         ----------     ----------     ----------

AVERAGE SALES PRICE (PER MCFE)                                           $     3.33     $     3.22     $     4.79

OPERATING AND OVERHEAD COSTS (PER MCFE):
Lease operating expenses                                                 $      .90     $      .64     $      .74
Production and severance taxes                                                  .19            .19            .34
General and administrative                                                     1.05           1.25           1.40
                                                                         ----------     ----------     ----------
            Total                                                        $     2.14     $     2.08     $     2.48
                                                                         ----------     ----------     ----------

OPERATING MARGIN (PER MCFE)                                              $     1.19     $     1.14     $     2.31

OTHER (PER MCFE):
Depreciation, depletion and amortization - oil and gas production        $      .58     $      .92     $     1.08

ESTIMATED NET PROVED RESERVES (AS OF THE RESPECTIVE PERIOD-END):
Natural gas (Bcf)                                                              68.6           56.7           45.0
Oil (MMbls)                                                                     3.9            1.7            1.3
Total (Bcfe)                                                                   91.8           66.7           53.0
Estimated Future Net Revenues ($MM)(2)(3)                                $    155.7     $    486.3     $    178.3
Present Value ($MM)(2)(3)                                                $     71.0     $     80.6     $     71.2
Standardized measure of discounted future net cash flows ($mm)(4)        $     48.5     $     54.3     $     48.0
</TABLE>
---------------------
(1)  Net of results of (i) hedging activities which increased the average oil
     price in 2001 by $.95 per Bbl and (ii) gas hedging activities which reduced
     the average gas price in 2001 by $.14 per Mcf and $.40 per Mcf in 2002, and
     $.48 per Mcf in 2003.

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

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

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

CRITICAL ACCOUNTING POLICIES

            The preparation of the consolidated financial statements requires
management of the Company to make a number of estimates and assumptions relating
to the reported amounts of

                                       22
<PAGE>

assets and liabilities and the disclosures of contingent assets and liabilities
at the date of the consolidated financial statements and the reported amounts of
revenues and expenses during the period. When alternatives exist among various
accounting methods, the choice of accounting method can have a significant
impact on reported amounts. The following is a discussion of the Company's
accounting estimates and judgments which management believes are most
significant in its application of generally accepted accounting principles used
in the preparation of the consolidated financial statements.

FULL COST CALCULATIONS

            GMX follows the full cost method of accounting for its oil and
natural gas properties. The full cost method subjects companies to quarterly
calculations of a "ceiling", or limitation on the amount of properties that can
be capitalized on the balance sheet. If GMX's capitalized costs are in excess of
the calculated ceiling, the excess must be written off as an expense.

            GMX's discounted present value of estimated future net revenues from
its proved oil and natural gas reserves is a major component of the ceiling
calculation, and represents the component that requires the most subjective
judgments. Estimates of reserves are forecasts based on engineering data,
projected future rates of production and the timing of future expenditures. The
process of estimating oil and natural gas reserves requires substantial
judgment, resulting in imprecise determinations, particularly for new
discoveries. All of GMX's reserve estimates are prepared by Sproule Associates,
Inc.

            The passage of time provides more qualitative information regarding
estimates of reserves, and revisions are made to prior estimates to reflect
updated information. For example, in 2002 our reserves were revised downward by
13.5 Bcfe. There can be no assurance that significant revisions will not be
necessary in the future. If future significant revisions are necessary that
reduce previously estimated reserve quantities, it could result in a full cost
property writedown. In addition to the impact of the estimates of proved
reserves on the calculation of the ceiling, estimates of proved reserves are
also a significant component of the calculation of the full cost pool
amortization.

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

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

            Because the ceiling calculation dictates that prices in effect as of
the last day of the applicable quarter are held constant indefinitely, the
resulting value is not indicative of the true fair value of the reserves. Oil
and natural gas prices have historically been cyclical and, on any

                                       23
<PAGE>

particular day at the end of a quarter, can be either substantially higher or
lower than GMX's long-term price forecast that is a barometer for true fair
value. Therefore, oil and natural gas property writedowns that result from
applying the full cost ceiling limitation, and that are caused by fluctuations
in price as opposed to reductions in the underlying quantities of reserves,
should not be viewed as absolute indicators of a reduction of the ultimate value
of the related reserves.

            The Company's asset retirement obligations ("ARO") consist primarily
of estimated costs of dismantlement, removal, site reclamation and similar
activities associated with its oil and gas properties. Statement of Financial
Accounting Standard ("SFAS") No. 143, "Accounting for Asset Retirement
Obligations," requires that the discounted fair value of a liability for an ARO
be recognized in the period in which it is incurred with the associated asset
retirement cost capitalized as part of the carrying cost of the oil and gas
asset. The recognition of an ARO requires that management make numerous
estimates, assumptions and judgments regarding such factors as the existence of
a legal obligation for an ARO; estimated probabilities, amounts and timing of
settlements; the credit-adjusted risk-free rate to be used; inflation rates; and
future advances in technology. In periods subsequent to initial measurement of
the ARO, the Company must recognize period-to-period changes in the liability
resulting from the passage of time and revisions to either the timing or the
amount of the original estimate of undiscounted cash flows. Increases in the ARO
liability due to passage of time impact net income as accretion expense. The
related capitalized cost, including revisions thereto, is charged to expense
through DD&A. At December 31, 2003, the Company's balance sheet included a
liability for ARO of $304,000.

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

            OIL AND GAS SALES. Oil and gas sales in the year ended December 31,
2003 decreased 10% to $5,367,370 compared to the year ended December 31, 2002,
due to decreased production. The average price per barrel of oil and mcf of gas
received in 2003 was $30.41 and $4.73, respectively, compared to $23.45 and
$3.03 in the year of 2002. During 2003, the Company hedged 180,000 Mcf of gas
through price swap agreements with a fixed price of $2.664 per Mcf. The price
swap agreements reduced sales by $438,400. Oil production for 2003 decreased
compared to 2002. Gas production decreased to 916 MMcf compared to 1,639 MMcf
for the year of 2002, a decrease of 44%. Decreased production and revenues in
2003 resulted from higher decline rates, production down time and a lack of
funds to workover wells.

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

            PRODUCTION AND SEVERANCE TAXES. Production and severance taxes
increased 3% to $384,069 in 2003 compared to $382,826 in 2002. Production and
severance taxes are assessed on the value of the oil and gas produced prior to
the effect of price swap agreements. As a result, the increase resulted
primarily from the increase in oil and gas sales prices mitigated by the
decrease in production.

                                       24
<PAGE>

            DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion
and amortization expense decreased $329,777 to $1,572,199 in 2003, down 17% from
2002. This decrease is due primarily to a decrease in production for 2003. The
oil and gas depreciation, depletion and amortization rate per equivalent unit of
production was $1.08 per Mcfe in 2003 compared to $0.92 per Mcfe in 2002.

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

            GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative
expense for 2003 was $1,578,865 compared to $2,577,358 for 2002, a decrease of
39%. This decrease of $998,523 was the result of a decrease in salaries and
payroll expenses of $741,000 and a decrease in legal and professional fees
primarily in connection with the Nabors Drilling lawsuit. The salary decrease
was a result of a decrease in administrative personnel. General and
administrative expense per equivalent unit of production was $1.40 per Mcfe for
the 2003 period compared to $1.25 per Mcfe for the comparable period in 2002. We
expect that 2004 general and administrative expense will increase compared to
2003 as a result of increases in our overall levl of activity.

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

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

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

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

            PRODUCTION AND SEVERANCE TAXES. Production and severance taxes
increased 13% to $382,826 in 2002 compared to $338,637 in 2001. Production and
severance taxes are assessed on the value of the oil and gas produced prior to
the effect of price swap agreements. As a result, the increase resulted
primarily from increased oil and gas sales.

                                       25
<PAGE>

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

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

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

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

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.

            In 2001, we raised $19.8 million in public offerings of common stock
and warrants. By December 31, 2001, these proceeds had been fully used,
primarily for development drilling. As a result of uncertainties relating to
pending litigation with a former drilling contractor, we were unable to obtain
additional advances to drill or for other purposes and were in default under the
terms of our credit facility from time to time from year end 2001 until August
2003. Due to these liquidity considerations there existed uncertainties about
our ability to continue operating as a going concern at year end 2001 and 2002.
We did not engage in any development activity in 2002 or 2003 due to a lack of
financial resources.

CASH FLOW--YEAR ENDED DECEMBER 31, 2003 COMPARED TO YEAR ENDED DECEMBER 31, 2002

            In 2003 we had a positive cash flow from operating activities of
$1,014,290 as a result of increased oil and gas prices during 2003. Our cash
flow from operating activities in 2002 was a deficit of $2,547,639 primarily due
to a reduction in net income and decreases in accounts

                                       26
<PAGE>

payable of $4,454,155. We received a net $464,315 in cash from investing
activities in 2003 compared to 2002 amounts of $1,267,851. The cash inflow in
2003 was primarily from the year end agreement with PVOG. The cash inflow in
2002 from investing activities primarily resulted from sale of our Kansas
properties for $4,245,163 which more than offset additions to oil and gas
properties of $3,014,288.

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

            In 2002 we had a deficit cash flow from operating activities of
$2,547,639 as a result of reductions in net income and from payments of 2001
accounts payable during 2002. Our cash flow from operating activities in 2001
was $8,016,600 primarily due to 2001 net income and increases in accounts
payable of $6,301,732. We received a net $1,267,831 in cash from investing
activities in 2002 compared to net cash expenditures of $26,700,785 in 2001. The
cash inflow in 2002 from investing activities primarily resulted from sale of
our Kansas properties for $4,245,163 which more than offset additions to oil and
gas properties of $3,014,288.

CREDIT FACILITY

            On October 31, 2000, we entered into a secured credit facility
provided by Local Oklahoma Bank, N.A. The credit facility provided for a line of
credit of up to $15 million (the "Commitment"), subject to a borrowing base
which is based on a periodic evaluation of oil and gas reserves which is reduced
monthly to account for production ("Borrowing Base"). The amount of credit
available to us at any one time under this credit facility is the lesser of the
Borrowing Base or the amount of the Commitment. The amount of this Borrowing
Base has been adjusted from time to time, most recently as of April 6, 2004 to
$6,170,000.

            The credit facility has been amended on several occasions to waive
non-payment default or to extend the maturity. The credit facility matured in
May 2003 and we remained in default under the facility until August 2003 when
the credit facility was amended to extend the maturity date of the promissory
note from May 1, 2003 to new maturity date of March 1, 2004. On March 15, 2004,
the bank approved an extension of the existing credit facility with the
following amended terms: New maturity date of September 1, 2004, Borrowing Base
of $6,310,000, monthly commitment reduction of $90,000 and all other terms in
the existing credit agreement to remain unchanged. See "Liquidity and Financing
Considerations" for additional information about a possible extension of
maturity to September 1, 2005.

            As of December 31, 2003, we had $6,690,000 outstanding under the
facility. As of March 1, 2004, we had $6,260,000 outstanding.

            Borrowings under the credit facility bear interest at the prime rate
plus 1%. The credit facility requires payment of an annual facility fee equal to
1 /2 % on the unused amount of the Borrowing Base. We are obligated to make
principal payments if the amount outstanding would exceed the Borrowing Base.
Borrowings under the credit agreement are secured by substantially all of our
oil and gas properties. The credit facility contains various affirmative and
restrictive covenants. The material covenants, which must be satisfied unless
the lender otherwise agrees:

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

                                       27
<PAGE>

     o    Require us to maintain a monthly debt service coverage ratio of at
          least 1.0 to 1. The debt service coverage ratio is defined in the
          credit facility generally as net income plus depreciation, depletion
          and amortization plus interest expense divided by monthly principal
          reduction requirements plus interest.

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

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

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

     o    Prohibit payment of dividends or repurchases of stock.

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

     o    Prohibit material changes in management.

SUBORDINATED NOTES

            In January 2004, we raised $1 million from the sale of 11% senior
subordinated notes due January 31, 2007 and five-year detachable warrants to
purchase 175,000 shares of common stock for $1.50 per share. The price of our
common shares as of that date was $4.01. For accounting purposes, the fair value
of the in-the-money warrants will increase the effective interest rate over the
term of the notes. In connection with this transaction, the lender under our
bank credit facility agreed to our incurrence of additional debt and entered
into an intercreditor and subordination agreement with the noteholders pursuant
to which the noteholders subordinated their rights to payment to the rights of
the bank under the credit facility. Principal reductions of $100,000 per year on
the subordinated notes are permitted in 2005 and 2006 subject to certain
conditions being met under the terms of the credit facility agreements.

            The Company is obligated to register the warrants and underlying
shares of common stock under the Securities Act of 1933 on or before June 30,
2004 in order to permit the holders to sell the warrants and underlying shares
without restrictions. If the Company fails to effect or maintain such
registration, it is obligated to issue additional warrants at the rate of 10,000
warrants per month such failure exists.


COMMON STOCK PRIVATE PLACEMENT

            In addition, on April 5, 2004, the Company closed a private
placement of 200,000 shares of common stock for $1,000,000 with an investor.
Proceeds of the transaction will be used for general corporate purposes. We are
also actively pursuing other sources of external financing through private
equity offerings and expect that additional placements may occur.


WORKING CAPITAL

            At December 31, 2003, we had a working capital deficit of $994,052.
Excluding our bank debt, our working capital as of December 31, 2003 would have
been $101,948. Total debt

                                       28
<PAGE>

outstanding at December 31, 2003 was $6.69 million, representing 23% of our
total capitalization. See liquidity below for 2004 issuances of subordinated
debt and equity. As discussed above, subsequent to December 31, 2003, we raised
$1 million in subordinated debt and raised $1 million from a sale of common
stock.

COMMITMENTS AND CAPITAL EXPENDITURES

            The following table reflects the Company's contractual obligations
as of December 31, 2003.

                               Payments Due by Period (In Thousands)
                      ----------------------------------------------------------
                                                                           More
    Contractual                     Less than                              than
    Obligations          Total       1 year      1-3 years   3-5 years   5 years
    -----------          -----       ------      ---------   ---------   -------

Long-term debt......  $6,690,000   $1,060,000   $5,630,000     ---         ---
Operating leases....     382,311      162,129     $220,182     ---         ---
Total...............  $7,072,311   $1,222,129   $5,880,182     ---         ---


            Other than obligations under our credit facility and the
subordinated notes, our commitments for capital expenditures relate to
development of oil and gas properties. We have not entered into drilling or
development commitments until such time as a source of funding for such
commitments is known to be available, either through financing proceeds, joint
venture arrangements, internal cash flow, additional funding under our bank
credit facility or working capital.

LIQUIDITY AND FINANCING CONSIDERATIONS

            As a result of the participation agreement with PVOG, the January
2004 private placement of notes and warrants and our April 2004 private
placement of common stock, our liquidity has substantially improved. Under our
participation agreement with PVOG, we have a carried interest in the first five
wells in Phase I and an option, but not an obligation to participate in any
remaining Phase I wells for a 30% interest. As a result, we have reduced our
costs and ownership relating to development of these wells. On April 14, 2004,
our bank lender made a commitment to extend the maturity of our current credit
facility to September 1, 2005, if we use the $1 million common stock placement
proceeds to prepay our 11% subordinated notes on or before May 14, 2004. We may
accept this proposal, but in the meantime are also actively evaluating several
proposals from other lenders to refinance our existing bank debt to maximize our
flexibility. In addition to refinancing our bank debt, we are continuing to
pursue alternatives to find other sources of capital including additional
development arrangements and private sources of equity or other debt financing.
There can be no assurance that we would be able to enter into any of these
financial arrangements. Until such sources become available, we have only
limited resources for property development and drilling, but we expect to have
sufficient cash flow, assuming a favorable oil and gas price environment, to
meet current obligations.

PRICE RISK MANAGEMENT

            We have entered into, and expect to periodically enter into,
financial price risk management activities with respect to a portion of
projected oil and gas production through

                                       29
<PAGE>

financial price swaps whereby we receive a fixed price for our production and
pay a variable market price to the contract counterparty. These activities are
intended to reduce our exposure to oil and gas price fluctuations. We may enter
into these instruments when we believe forward market conditions are relatively
favorable, but we do not expect to manage at any time more than 75% of our total
production. The gains and losses realized as a result of these activities are
substantially offset in the cash market when the commodity is delivered. During
2002, we entered into price swap agreements for 50,000 and 40,000 MMBtu of
natural gas per month at a fixed price of $2.66 and $2.67 per MMBtu,
respectively. These arrangements managed approximately 52% of our estimated
monthly gas production based on our December 31, 2001 reserve report. This hedge
reduced our average realized gas price in 2002 from $3.43 to $3.03 per Mcf. This
same hedge affected January and February of 2003, by reducing our average
realized gas price for 2003 from $5.69 to $5.21 per Mcf.

IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED

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

            In December 2003, the FASB issued FASB Interpretation No. 46
(revised December 2003), Consolidation of Variable Interest Entities, which
addresses how a business enterprise should evaluate whether it has a controlling
financial interest in an entity through means other than voting rights and
accordingly should consolidate the entity. FIN 46R replaces FASB Interpretation
No. 46, Consolidation of Variable Interest Entities, which was issued in January
2003. The Company will be required to apply FIN 46R to variable interests in
VIEs created after December 31, 2003. For variable interests in VIEs created
before January 1, 2004, the Interpretation will be applied beginning on January
1, 2005. For any VIEs that must be consolidated under FIN 46R that were created
before January 1, 2004, the assets, liabilities and noncontrolling interests of
the VIE initially would be measured at their carrying amounts with any
difference between the net amount added to the balance sheet and any previously
recognized interest being recognized as the cumulative effect of an accounting
change. If determining the carrying amounts is not practicable, fair value at
the date FIN 46R first applies may be used to measure the assets, liabilities
and noncontrolling interest of the VIE. The Company anticipates that this
standard will not have an impact on the Company's financial statements because
it does not own any interests in variable interest entities.

            SFAS Statement of 150, Accounting for Certain Financial Instruments
with Characteristics of Both Liabilities and Equity, ("SFAS 150") was issued in
May, 2003. SFAS 150 establishes standards for the classification and measurement
of certain financial instruments with characteristics of both liabilities and
equity. SFAS 150 also includes required disclosures for financial instruments

                                       30
<PAGE>

within its scope. SFAS 150 was effective for instruments entered into or
modified after May 31, 2003 and otherwise will be effective as of January 1,
2004, except for mandatorily redeemable financial instruments. For certain
mandatorily financial instruments, FSAS 150 will be effective on January 1,
2005. The effective date has been deferred indefinitely for certain other types
of mandatorily redeemable financial instruments. The Company currently does not
have any financial instruments that are within the scope of SFAS 150.

            During 2003, a reporting issue arose regarding the application of
certain provisions of SFAS No. 141, "Business Combinations," and SFAS No. 142,
"Goodwill and Other Intangible Assets," to companies in the extractive
industries, including oil and gas companies. The issue is whether SFAS No. 142
requires registrants to classify the costs of mineral rights associated with
extracting crude oil and natural gas as intangible assets in the balance sheet,
apart from other capitalized oil and gas property costs, and provide specific
footnote disclosures. The EITF has added the treatment of oil and gas mineral
rights to an upcoming agenda, which may result in a change in how GMX classifies
these assets. Historically, the Company has included the costs of mineral rights
associated with extracting crude oil and natural gas as a component of oil and
gas properties. If it is ultimately determined that SFAS No. 142 requires oil
and gas companies to classify costs of mineral rights associated with extracting
crude oil and natural gas as a separate intangible assets line item on the
balance sheet, net of amortization, the Company most likely would be required to
reclassify certain amounts out of oil and gas properties and into a separate
intangible assets line item. The Company's cash flows and results of operations
would not be affected since such intangible assets would continue to be depleted
and assessed for impairment in accordance with existing full cost accounting
rules.

            If it is ultimately determined that SFAS No. 142 requires oil and
gas companies to classify costs of mineral rights associated with extracting
crude oil and natural gas as a separate intangible assets line item on the
balance sheet, the Company believes that the amount of costs that may be
required to be reclassified would be less than $500,000. The Company does not
believe the classification of the costs of mineral rights associated with
extracting oil and gas as intangible assets would have any impact on compliance
with covenants under the Company's debt agreements.

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.

                                       31
<PAGE>

            The forward looking statements in this report are subject to all the
risks and uncertainties which are described in this document. We may also make
material acquisitions or divestitures or enter into financing transactions. None
of these events can be predicted with certainty or not taken into consideration
in the forward looking statements.

            For all of these reasons, actual results may vary materially from
the forward looking statements and we cannot assure you that the assumptions
used are necessarily the most likely. We will not necessarily update any forward
looking statements to reflect events or circumstances occurring after the date
the statement is made except as may be required by federal securities laws.

            There are a number of risks that may affect our future operating
results and financial condition. These are described below.

RISK FACTORS RELATED TO GMX

THERE ARE SUBSTANTIAL UNCERTAINTIES ABOUT OUR CURRENT FINANCIAL CONDITION WHICH
CURTAIL OUR ABILITY TO CONDUCT FURTHER DRILLING.

            As discussed above, our bank debt matures on September 1, 2004, but
our bank has offered to extend the maturity to September 1, 2005, subject to
certain conditions. We are actively seeking proposals from other lenders to
refinance our existing bank debt to maximize our financial flexibility. In
addition, we are dependent on the availability of additional financial resources
to pursue further drilling and, accordingly, we may not be able to fully realize
the value of our proved undeveloped reserves. Until these uncertainties are
resolved, our ability to implement our business plan will continue to be
materially adversely affected and our financial condition may be impaired.

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

            Ken L. Kenworthy, Jr. and Ken L. Kenworthy, Sr. beneficially own
approximately 31% and 15% respectively, of our outstanding common stock. These
shareholders, acting together, will be able to control the outcome of
shareholder votes, including votes concerning the election of directors, the
adoption or amendment of provisions in our certificate of incorporation or
bylaws and the approval of mergers and other significant corporate transactions.
This concentrated ownership makes it unlikely that any other holder or group of
holders of common stock will be able to affect the way we are managed or the
direction of our business. These factors may also delay or prevent a change in
the management or voting control of GMX.

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

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

                                       32
<PAGE>

WE HAVE LIMITED OPERATING HISTORY.

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

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

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

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

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

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

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

            To reduce our exposure to fluctuations in the prices of oil and
natural gas, we have in the past, and may in the future, enter into hedging
arrangements. Hedging arrangements expose us to risk of financial loss in some
circumstances, including the following:

               o    production is less than expected;

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

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

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

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

                                       33
<PAGE>

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

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

            Unless we successfully replace the reserves that we produce, our
reserves will decline, resulting eventually in a decrease in oil and natural gas
production and lower revenues and cash flows from operations. The business of
exploring for, developing or acquiring reserves is capital intensive. We
currently are not able to make the necessary capital investment to maintain or
expand our oil and natural gas reserves. In addition, our drilling activities
are subject to numerous risks, including the risk that no commercially
productive oil or gas reserves will be encountered.

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

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

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

            The estimates of the quantities of our proved undeveloped reserves
and the estimated future net revenues from such reserves is based on certain
assumptions about our ownership in the underlying properties. As a result of the
PVOG participation agreement entered into in December 2003, our ownership
interest in proved undeveloped reserves in the Phase I acreage has been reduced
to reflect PVOG's new ownership position. Our ownership position in wells in
Phase II will be reduced as well if PVOG successfully completes Phase I and our
current reserve estimates assume that Penn Virginia will complete Phase I and a
limited amount of Phase II. Our reserve estimates will be increased if Penn
Virginia does not complete Phase I and will be decreased if Penn Virginia fully
completes Phase II.

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 2002, we received gas and oil prices at the wellhead ranging
from $1.23 to $4.68 per Mcf and $15.78 to $29.16 per Bbl. In 2003, we received
gas and oil prices ranging

                                       34
<PAGE>

from $4.01 to $8.33 per Mcf and $25.72 to $35.08 per Bbl. We cannot predict oil
and natural gas prices and prices may decline in the future. The following
factors have an influence on oil and natural gas prices:

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

               o    storage availability;

               o    weather conditions;

               o    market uncertainty;

               o    domestic and foreign governmental regulations;

               o    the availability and cost of alternative fuel sources;

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

               o    the price of foreign oil and natural gas;

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

               o    overall economic conditions.

WE MAY ENCOUNTER DIFFICULTY IN OBTAINING EQUIPMENT AND SERVICES.

            Higher oil and gas prices and increased oil and gas drilling
activity, such as those we experienced in 2003, generally stimulate increased
demand and result in increased prices and unavailability for drilling rigs,
crews, associated supplies, equipment and services. While we are currently
experiencing no difficulty obtaining drilling rigs, crews, associated supplies,
equipment and services because of a recent decrease in prices and in activity,
such difficulty could occur in the future. These shortages could also result in
increased costs, delays in timing of anticipated development or cause interests
in oil and gas leases to lapse. We cannot be certain that we will be able to
implement our drilling plans or at costs that will be as estimated or acceptable
to us.

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

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

                                       35
<PAGE>

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

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

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

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

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

               o    the presence of unanticipated pressure or irregularities in
                    formations;

               o    accidents;

               o    title problems;

               o    weather conditions;

                                       36
<PAGE>

               o    compliance with governmental requirements; and

               o    shortages or delays in the delivery of equipment.

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

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

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

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

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

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

               o    injury or loss of life;

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

               o    pollution or other environmental damage;

               o    clean-up responsibilities;

               o    regulatory investigation and penalties; and

               o    other losses resulting in suspension of our operations.

            In accordance with customary industry practice, we maintain
insurance against some, but not all, of the risks described above with a general
liability limit of $2 million. We do not maintain insurance for damages arising
out of exposure to radioactive material. Even in the case of risks against which
we are insured, our policies are subject to limitations and exceptions that
could cause us to be unprotected against some or all of the risk. The occurrence
of an uninsured loss could have a material adverse effect on our financial
condition or results of operations.

GOVERNMENTAL REGULATIONS COULD ADVERSELY AFFECT OUR BUSINESS.

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

                                       37
<PAGE>

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

ENVIRONMENTAL LIABILITIES COULD ADVERSELY AFFECT OUR BUSINESS.

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

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

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

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

               o    blowouts, cratering and explosions.

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

COMPETITION IN THE OIL AND GAS INDUSTRY IS INTENSE, AND WE ARE SMALLER AND HAVE
A MORE LIMITED OPERATING HISTORY THAN MANY OF OUR COMPETITORS.

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

                                       38
<PAGE>

WE HAVE NOT PAID DIVIDENDS AND DO NOT ANTICIPATE PAYING ANY DIVIDENDS ON OUR
COMMON STOCK IN THE FORESEEABLE FUTURE.

            We anticipate that we will retain all future earnings and other cash
resources for the future operation and development of our business. We do not
intend to declare or pay any cash dividends in the foreseeable future. Payment
of any future dividends will be at the discretion of our board of directors
after taking into account many factors, including our operating results,
financial condition, current and anticipated cash needs and other factors. The
declaration and payment of any future dividends is currently prohibited by our
credit agreement and may be similarly restricted in the future.

ITEM 7. FINANCIAL STATEMENTS

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

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

            Not applicable.

ITEM 8A. CONTROLS AND PROCEDURES

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


                                       39
<PAGE>

                                    PART III

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

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

Name                      Age    Position Currently Held
--------------------------------------------------------------------------------
Ken L. Kenworthy, Jr.     47     President, Chief Executive Officer and Director
Ken L. Kenworthy, Sr.     68     Executive Vice President, Secretary, Treasurer,
                                 Chief Financial Officer and Director
T. J. Boismier            69     Director
Steven Craig              47     Director
Kyle Kenworthy            42     Vice President - Land

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

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

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

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

                                       40
<PAGE>

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

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

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

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

SIGNIFICANT EMPLOYEES

            Keith Leffel, age 54, has been employed as our natural gas marketer
and pipeline operations manager since November 2001. Since 1986, Mr. Leffel
formed and operated GKL Energy Services Company, a company that assists
producers with gas marketing services.

            Rick Hart, Jr. a, petroleum engineer, age 47, was hired in January,
2004 as Operations Manager. He has 24 years of experience in all aspects of
operations, including specific expertise in drilling, completion and production
in the East Texas reservoirs. He worked with Focus Energy for nine years and had
responsibility for 319 producing wells.

CONSULTANT

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

TERMS

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

                                       41
<PAGE>

SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

            Section 16(a) of the Securities and Exchange Act of 1934 requires
directors and executive officers of the Company and persons who beneficially own
more than 10% of the Company's common stock to file reports of ownership and
changes in ownership of the Company's common stock with the Securities and
Exchange Commission. The Company is required to disclose delinquent filings of
reports by such persons.

            Based on a review of the copies of such reports and amendments
thereto received by the Company, or written representations that no filings were
required, the Company believes that all Section 16(a) filing requirements
applicable to its executive officers, directors and 10% shareholders were met
during 2003.

AUDIT COMMITTEE MATTERS

            During 2003, the Company had a standing audit committee consisting
of Messrs. Boismier and Craig. Neither of these individuals qualify as a
"financial expert" as contemplated by the rules of the Securities and Exchange
Commission. These individuals were appointed to the Company's audit committee
before the adoption of the financial expert rules. The Company is endeavoring to
recruit an additional independent board member to satisfy the requirements of
the NASDAQ National Market System that the Company have three independent board
members on its audit committee and the Company will attempt to recruit a
candidate that will also qualify as a "financial expert."

CODE OF ETHICS

            The Company has adopted a Code of Business Conduct and Ethics
("Code") that is applicable to all of its officers, directors and employees,
including the Company's principal executive, financial and accounting officers.
A copy of the Code is filed as an exhibit to this report.

ITEM 10. EXECUTIVE COMPENSATION

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

SUMMARY COMPENSATION TABLE
<TABLE><CAPTION>
                                          ANNUAL COMPENSATION
                                     ------------------------------
                                                       OTHER ANNUAL     ALL OTHER
NAME AND PRINCIPAL POSITION   YEAR   SALARY    BONUS   COMPENSATION   COMPENSATION(1)
---------------------------   ----   ------    -----   ------------   ---------------
<S>                          <C>   <C>       <C>           <C>          <C>
Ken L. Kenworthy, Jr.         2001  $171,833  $30,000       --           $5,104
 President and Chief          2002   175,000   30,000       --            8,385
 Executive Officer            2003   157,500      --        --              --

Ken L. Kenworthy, Sr.         2001   171,833   30,000       --            5,104
 Executive Vice President,    2002   175,000   30,000       --            8,385
 Secretary, Treasurer and     2003   157,500      --        --              --
 Chief Financial Officer

Kyle Kenworthy                2001    56,000    5,000       --            4,070
 Vice President--Land         2002    72,000      --        --            5,232
                              2003    72,000    1,000       --            2,599
</TABLE>

(1)  All Other Compensation includes amounts contributed by GMX for the account
     of the named individual to GMX'S 401(k) plan and gasoline allowance for
     Kyle Kenworthy.

                                       42
<PAGE>

            There were no options granted to the named executive officers in
2003. The following table reflects options exercised during 2003 or outstanding
at year end for the named executive officers.

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

                                           NUMBER OF SECURITIES             VALUE OF
                                          UNDERLYING UNEXERCISED    UNEXERCISED IN-THE-MONEY
                                               OPTIONS AT                  OPTIONS AT
                  SHARES                    DECEMBER 31, 2003         DECEMBER 31, 2003(1)
                 ACQUIRED     VALUE    --------------------------  --------------------------
NAME            ON EXERCISE  REALIZED  EXERCISABLE  UNEXERCISABLE  EXERCISABLE  UNEXERCISABLE
--------------  -----------  --------  -----------  -------------  -----------  -------------
<S>                <C>        <C>        <C>           <C>            <C>           <C>
Kyle Kenworthy      N/A        N/A        12,500        7,500          N/A           N/A
</TABLE>
------------------
(1)  There was no value of unexercised in-the-money options at December 31, 2003
     because the option exercise price exceeded the market price per share of
     Common Stock on December 31, 2003.

COMPENSATION OF DIRECTORS

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

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

            The following table sets forth certain information regarding the
beneficial ownership of our common stock as of April 7, 2004, by (i) each person
or group of affiliated persons known to be the beneficial owner of more than 5%
of our outstanding common stock; (ii) each of our directors; (iii) each of our
executive officers; and (iv) all of our directors and executive officers as a
group.

                                       43
<PAGE>

            As of April 7, 2004, there were 6,775,000 shares of common stock
outstanding. Except as otherwise listed below, each named beneficial owner has
sole voting and investment power with respect to the shares listed.

                                                NUMBER OF       PERCENT
BENEFICIAL OWNER                                 SHARES         OF TOTAL
----------------                                 ------         --------

Ken L. Kenworthy, Jr. (1) (2)..............      928,185          13.7%
Karen Kenworthy(2)(6)......................      928,157          13.7%
Ken L. Kenworthy, Sr.(2)...................      967,324          14.3%
Newton Family Group(7).....................      900,000          13.3%
T. J. Boismier (3).........................       18,750            *
Steven Craig(4)............................        5,000            *
Kyle Kenworthy(5)..........................       12,500            *
All executive officers and directors
  as a group (5 persons)...................    1,931,759          28.5%
-------------------
*  Less than 1%.

(1)  Shares owned by Mr. Kenworthy, Jr. excludes 928,157 shares owned by his
     wife as to which he disclaims beneficial ownership.

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

(3)  Includes 2,500 shares which Mr. Boismier has the right to acquire upon
     exercise of Class A warrants and 11,250 shares he has the right to acquire
     on exercise of options exercisable within 60 days.

(4)  Includes 5,000 shares which Mr. Craig has the right to acquire on exercise
     of options exercisable within 60 days.

(5)  Includes 12,500 shares which Mr. Kenworthy has the right to acquire on
     exercise of options exercisable within 60 days.

(6)  Shares owned by Karen Kenworthy excludes 928,185 shares owned by her
     husband Ken L. Kenworthy, Jr., as to which she disclaims beneficial
     ownership.

(7)  This ownership information is based on information provided by the Newton
     Family Group. The Newton Family Group consists of William C. Newton and
     Gloria A. Newton, husband and wife, Newton Discretionary Trust, as to which
     William C. Newton is the sole trustee; and Newton Investment Partners, as
     to which William C. Newton is the managing partner. William C. Newton and
     Gloria A. Newton have beneficial ownership of 900,000 shares which includes
     775,000 shares beneficially owned by Newton Investment Partners and 100,000
     shares that may be acquired upon the exercise of warrants held by Newton
     Investment Partners. The business address of the Newton Family Group is c/o
     Notwen Corporation, 660 East Broadway, Jackson Hole, Wyoming 83001.

                                       44
<PAGE>

EQUITY COMPENSATION PLAN INFORMATION

            The following table sets forth information as of December 31, 2003
relating to equity compensation plans.
<TABLE><CAPTION>

                                  NUMBER OF SHARES TO BE                                   REMAINING SHARES AVAILABLE FOR
                                 ISSUED UPON EXERCISE OF    WEIGHTED-AVERAGE EXERCISE     FUTURE ISSUANCE UNDER EQUITY
     PLAN CATEGORY                  OUTSTANDING OPTIONS    PRICE OF OUTSTANDING OPTIONS         COMPENSATION PLANS
-----------------------------    -----------------------   ----------------------------   -------------------------------
<S>                                     <C>                         <C>                             <C>
Equity Compensation Plans
Approved by Shareholders                 138,000                     $3.16                           411,000

Equity Compensation Plans Not
Approved by Shareholders                  75,000                     $1.00                             --
</TABLE>

ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K

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

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

            (b) The Company filed a report on Form 8-K dated December 20, 2003
            reporting under Item 5 execution of a participation agreement with
            Penn Virginia Oil & Gas Corporation.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

            The following table sets forth the fees billed by the company's
independent auditor, KPMG LLP for each of the last 2 years:

                                                                FEES BILLED
                                                                -----------
                             TYPE                             2002       2003
                             ----                             ----       ----

            Audit fees (excluding audit related fees)        60,000     65,000
            Audit related fees                                 --         --
            Tax fee                                            --         --
            All other fees                                     --         --

            The Audit Committee pre-approves all audit and non-audit services,
if any, performed by the independent auditor.There were no audited related tax
or other services provided by the independent auditor in 2002 or 2003.

                                       45
<PAGE>

                                   SIGNATURES

            Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly authorized.



                                     GMX RESOURCES INC.


Dated: April 14, 2004                By: /s/ Ken L. Kenworthy, Jr.
                                         --------------------------------
                                         Ken L. Kenworthy, Jr., President


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


       Signatures                          Title                       Date
       ----------                          -----                       ----

/s/ Ken L. Kenworthy, Jr.          President and Director         April 14, 2004
----------------------------                                      --------------
Ken L. Kenworthy, Jr.


/s/ Ken L. Kenworthy, Sr.          Executive Vice President,      April 14, 2004
----------------------------       Chief Financial Officer        --------------
Ken Kenworthy, Sr.                 and Director


/s/ Steven Craig                   Director                       April 14, 2004
----------------------------                                      --------------
Steven Craig


/s/ T. J. Boismier                 Director                       April 14, 2004
----------------------------                                      --------------
T. J. Boismier



                                       46
<PAGE>




                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



Independent Auditors' Report ..............................................  F-2

Consolidated Balance Sheets,
   December 31, 2002 and 2003 .............................................  F-3

Consolidated Statements of Operations,
   Years Ended December 31, 2002 and 2003 .................................  F-4

Consolidated Statements of Changes in Shareholders' Equity,
   Years Ended December 31, 2002 and 2003 .................................  F-5

Consolidated Statements of Cash Flows,
   Years Ended December 31, 2002 and 2003 .................................  F-6

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


















                                       F-1
<PAGE>
                          INDEPENDENT AUDITORS' REPORT


The Board of Directors and Shareholders
GMX Resources Inc.:

We have audited the accompanying consolidated balance sheets of GMX Resources
Inc. and subsidiaries as of December 31, 2002 and 2003 and the related
consolidated statements of operations, changes in shareholders' equity, and cash
flows for the years then ended. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.

We conducted our 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, 2002 and 2003 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.

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



                                                                        KPMG LLP


Oklahoma City, Oklahoma
April 6, 2004, except as to Note L which is as of April 14, 2004






                                       F-2
<PAGE>
                               GMX RESOURCES INC.
                           CONSOLIDATED BALANCE SHEETS
                           DECEMBER 31, 2002 AND 2003
<TABLE><CAPTION>
                                                                    ------------      ------------
                                                                        2002              2003
                                                                    ------------      ------------
<S>                                                                 <C>               <C>
                                     ASSETS
CURRENT ASSETS:
     Cash and cash equivalents                                      $    543,917      $    637,522
     Accounts receivable--interest owners                                 52,576           299,442
     Accounts receivable--oil and gas revenues                           513,898           432,844
     Inventories                                                         236,704           235,004
     Prepaid expenses and other current assets                            11,609            11,608
                                                                    ------------      ------------
              Total current assets                                     1,358,704         1,616,420
                                                                    ------------      ------------

OIL AND GAS PROPERTIES, AT COST, BASED ON THE FULL COST METHOD
OF ACCOUNTING FOR OIL AND GAS PROPERTIES                              32,881,893        32,449,096
     Less accumulated depreciation, depletion, and amortization       (3,522,584)       (4,788,779)
                                                                    ------------      ------------
                                                                      29,359,309        27,660,317
                                                                    ------------      ------------

OTHER PROPERTY AND EQUIPMENT                                           3,200,345         3,200,345
     Less accumulated depreciation                                      (656,572)         (991,889)
                                                                    ------------      ------------
                                                                       2,543,773         2,208,456
                                                                    ------------      ------------
OTHER ASSETS                                                              57,646            16,013
                                                                    ------------      ------------
              TOTAL ASSETS                                          $ 33,319,432      $ 31,501,206
                                                                    ============      ============


                      LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
     Accounts payable                                               $  2,426,715      $  1,134,500
     Accrued expenses                                                     81,855            64,887
     Accrued interest                                                      6,764            29,703
     Revenue distributions payable                                       407,849           285,382
     Derivative financial instruments                                    421,300                --
     Current portion of long-term debt                                 8,100,000         1,060,000
                                                                    ------------      ------------
              Total current liabilities                               11,444,483         2,610,472

LONG-TERM DEBT, LESS CURRENT PORTION                                          --         5,630,000

OTHER LIABILITIES                                                        267,486           678,169

DEFERRED INCOME TAXES                                                         --                --

SHAREHOLDERS' EQUITY:
     Common stock, par value $.001 per share--authorized
       50,000,000 shares issued and outstanding 6,550,000
       and 6,575,000 shares in 2002 and 2003, respectively                 6,550             6,575
     Additional paid-in capital                                       20,905,197        20,959,973
     Retained earnings                                                 1,117,016         1,652,017
     Other comprehensive income (loss)                                  (421,300)               --
                                                                    ------------      ------------
              Total shareholders' equity                              21,607,463        22,618,565
                                                                    ------------      ------------

              TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY            $ 33,319,432      $ 31,501,206
                                                                    ============      ============
</TABLE>
See accompanying notes to consolidated financial statements.

                                       F-3
<PAGE>
                               GMX RESOURCES INC.
                      CONSOLIDATED STATEMENTS OF OPERATIONS
                     YEARS ENDED DECEMBER 31, 2002 AND 2003

<TABLE><CAPTION>
                                                                                 ------------------------------
                                                                                     2002              2003
                                                                                 ------------      ------------
<S>                                                                              <C>               <C>
REVENUE
     Oil and gas sales                                                           $  5,970,792      $  5,367,370
     Interest income                                                                    5,169             2,592
     Other income                                                                      12,381            18,832
                                                                                 ------------      ------------
              Total revenue                                                         5,988,342         5,388,794
                                                                                 ------------      ------------

EXPENSES
     Lease operations                                                               1,324,481           827,513
     Accretion expense on asset retirement obligations                                     --            22,521
     Production and severance taxes                                                   382,826           384,069
     Depreciation, depletion and amortization                                       1,901,976         1,549,678
     Interest                                                                         510,472           439,313
     General and administrative                                                     2,577,388         1,578,865
                                                                                 ------------      ------------
              Total expenses                                                        6,697,142         4,801,959
                                                                                 ------------      ------------

              Income (loss) before income taxes                                      (708,800)          586,835

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

     Net income before cumulative effect of a change in accounting principle     $   (445,800)     $    586,835
                                                                                 ============      ============

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

                                                                                 ============      ============
     Net income (loss)                                                           $   (445,800)     $    535,001
                                                                                 ============      ============

     EARNINGS (LOSS) PER SHARE--Before Cumulative Effect                         $      (0.07)     $       0.09
                                                                                 ============      ============
     EARNINGS (LOSS) PER SHARE - Cumulative Effect                               $         --      $       0.01
                                                                                 ============      ============
     EARNINGS (LOSS) PER SHARE - Basic and Diluted                               $      (0.07)     $       0.08
                                                                                 ============      ============
     WEIGHTED AVERAGE COMMON SHARES - Basic and Diluted                             6,550,000         6,560,000
                                                                                 ============      ============
</TABLE>

See accompanying notes to consolidated financial statements.

                                       F-4
<PAGE>
                               GMX RESOURCES INC.
            CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY
                     YEARS ENDED DECEMBER 31, 2003 AND 2002



<TABLE><CAPTION>
                                                                                         RETAINED      ACCUMULATED
                                                     COMMON STOCK        ADDITIONAL      EARNINGS         OTHER
                                                ---------------------     PAID-IN     (ACCUMULATED)   COMPREHENSIVE      TOTAL
                                                  SHARES      AMOUNT      CAPITAL        DEFICIT)     INCOME (LOSS)      EQUITY
                                                ---------   ---------   -----------   -------------   -------------   -----------
<S>                                             <C>         <C>         <C>           <C>             <C>             <C>
BALANCE AT DECEMBER 31, 2001                    6,550,000   $   6,550   $20,905,197   $   1,562,816              --   $22,474,563

Net income                                                                                 (445,800)             --      (445,800)
Adjustment for derivative losses reclassified
  into oil and gas sales                               --          --            --              --         423,865       423,865
Change in fair value of derivative instruments         --          --            --              --        (845,165)     (845,165)
                                                                                                                      -----------
Total comprehensive loss                               --          --            --              --              --      (867,100)
                                                ---------   ---------   -----------   -------------   -------------   -----------
BALANCE AT DECEMBER 31, 2002                    6,550,000   $   6,550   $20,905,197   $   1,117,016        (421,300)  $21,607,463
                                                =========   =========   ===========   =============   =============   ===========
Compensation from option grant                         --          --        29,801              --              --        29,801
Options exercised                                  25,000          25        24,975              --              --        25,000
Adjustment for derivative losses reclassified
  into oil and gas sales                               --          --            --              --         438,400       438,400
Change in fair value of derivative instruments         --          --            --              --         (17,100)      (17,100)
                                                                                                                      -----------
Net income                                             --          --            --         535,001              --       535,001
Total comprehensive income                                                                                                956,301
                                                =========   =========   ===========   =============   =============   ===========
BALANCE AT DECEMBER 31, 2003                    6,575,000   $   6,575   $20,959,973   $   1,652,017              --   $22,618,565
                                                =========   =========   ===========   =============   =============   ===========
</TABLE>

See accompanying notes to consolidated financial statements.


<PAGE>
                               GMX RESOURCES INC.
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                     YEARS ENDED DECEMBER 31, 2002 AND 2003



<TABLE><CAPTION>
                                                                    2002              2003
                                                                ------------      ------------
<S>                                                             <C>               <C>
CASH FLOWS DUE TO OPERATING ACTIVITIES
    Net income (loss)                                           $   (445,800)     $    535,001
    Adjustments to reconcile net income (loss) to net
    cash provided by (used in ) operating activities:
        Compensation-stock options                                        --            29,801
        Accretion expense on asset retirement obligations                 --            22,521
        Depreciation, depletion, and amortization                  1,901,976         1,549,678
        Deferred income tax benefit                                 (263,000)               --
        Gain on sale of other property and equipment                  (3,775)               --
        Gain on sale of investments                                   (3,714)               --
        Cumulative effect of change in accounting principle               --            51,834
        Decrease (increase) in:
             Accounts receivable                                     744,636            84,188
             Inventory and prepaid expenses                           19,874             1,701
             Other assets                                             13,605            41,633
        Increase (decrease) in:
             Accounts payable                                     (4,454,155)       (1,292,215)
             Accrued expenses and other liabilities                 (123,934)          112,615
             Revenue distributions payable                            66,648          (122,467)
                                                                ------------      ------------

                 Net cash provided by (used in)
                 operating activities                             (2,547,639)        1,014,290
                                                                ------------      ------------

CASH FLOWS DUE TO INVESTING ACTIVITIES
    Additions to oil and gas properties                           (3,014,288)         (236,617)
    Purchase of property and equipment                               (45,882)               --
    Proceeds from sale of other property and equipment                 5,000                --
    Proceeds from sale of investments                                 77,838                --
    Proceeds from sale of oil and gas properties                   4,245,163           700,932
                                                                ------------      ------------
                 Net cash provided by investing activities         1,267,831           464,315
                                                                ------------      ------------

CASH FLOWS DUE TO FINANCING ACTIVITIES
    Advance on borrowings                                          5,898,000                --
    Payments on debt                                              (4,078,000)       (1,410,000)
    Issuance of equity                                                    --            25,000
                                                                ------------      ------------
                 Net cash provided by (used in) financing
                 activities                                        1,820,000        (1,385,000)
                                                                ------------      ------------

Net increase in cash                                                 540,192            93,605

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR                         3,725           543,917
                                                                ------------      ------------

CASH AND CASH EQUIVALENTS AT END OF YEAR                        $    543,917      $    637,522
                                                                ============      ============

CASH PAID FOR INTEREST                                          $    510,472      $    376,585
                                                                ============      ============
</TABLE>

See accompanying notes to consolidated financial statements.

                                       F-6
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


NOTE A--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include the
accounts of GMX Resources Inc. (the "Company or GMX") and its wholly-owned
subsidiaries, Endeavor Pipeline, Inc. and Expedition Natural Resources, Inc.
Endeavor Pipeline, Inc. owns and operates natural gas gathering facilities in
East Texas. Expedition Natural Resources, Inc. owns undeveloped leases,
primarily in East Texas. All significant intercompany accounts and transactions
have been eliminated. Accounting policies used by the Company reflect industry
practices and conform to accounting principles generally accepted in the United
States of America. The more significant of such policies are briefly described
below.

ORGANIZATION: The Company was formed in January 1998. In February 1998, the
Company purchased, for approximately $6,000,000, oil and gas properties and
commenced operations. The Company is primarily engaged in acquisition,
exploration, and development of properties for the production of crude oil and
natural gas in Oklahoma, Louisiana, New Mexico, and Texas.

CASH AND CASH EQUIVALENTS: GMX considers all highly liquid investments with
maturities of three months or less at the time of purchase to be cash
equivalents.

INVENTORIES: Inventories consist of lease and well equipment and crude oil on
hand. The Company plans to utilize the lease and well equipment in its ongoing
operations and it is carried at the lower of cost or market. Treated and stored
crude oil inventory on hand at the end of the year is valued at cost.

PROPERTY AND EQUIPMENT: The Company follows the full cost method of accounting
for its oil and gas properties. Accordingly, all costs incidental to the
acquisition, exploration and development of oil and gas properties, including
costs of undeveloped leasehold, dry holes and leasehold equipment are
capitalized. Net capitalized costs are limited to the estimated future net
revenues, discounted at 10% per annum, from proved oil, natural gas, and natural
gas liquid reserves. Capitalized costs are depleted by an equivalent
unit-of-production method, converting oil to gas at the ratio of one barrel of
oil to six thousand cubic feet of natural gas. No gain or loss is recognized
upon disposal of oil and gas properties unless such disposal significantly
alters the relationship between capitalized costs and proved reserves. Revenues
from services provided to working interest owners of properties which GMX also
owns an interest in excess of related costs incurred are accounted for as
reductions of capitalized costs of oil and gas properties.

The sale of the Company's Kansas properties in September 2002 did not result in
a gain or loss. The December 2003 sale of an interest in our East Texas
properties also did not result in a gain or loss. All proceeds from the sales
were applied to the full cost pool.

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

                                       F-7
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


Pipeline and gathering system assets and other long-lived assets are
periodically assessed to determine if circumstances indicate that the carrying
amount of an asset may not be recoverable. SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," was issued in August 2001. This
statement addresses financial accounting and reporting for the impairment or
long-lived assets. This statement supersedes SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for long-Lived Assets to Be Disposed Of."
This statement requires (a) recognition of an impairment loss only if the
carrying amount of a long-lived asset is not recoverable from its undiscounted
cash flows and (b) measurement of an impairment loss as the difference between
the carrying amount and fair value of the asset. The Company adopted the
statement January 1, 2002 with no material impact on the Company's results of
operations or financial position.

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

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

REVENUE RECOGNITION AND NATURAL GAS BALANCING: Oil and gas revenues are
recognized when sold. During the course of normal operations, the Company and
other joint interest owners of natural gas reservoirs will take more or less
than their respective ownership share of the natural gas volumes produced. These
volumetric imbalances are monitored over the lives of the wells' production
capability. If an imbalance exists at the time the wells' reserves are depleted,
cash settlements are made among the joint interest owners under a variety of
arrangements.

The Company follows the sales method of accounting for gas imbalances. A
liability is recorded when the Company's excess takes of natural gas volumes
exceed its estimated remaining recoverable reserves. No receivables are recorded
for those wells where the Company has taken less than its ownership share of gas
production. There are no significant imbalances as of December 31, 2002 or 2003.

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

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

                                       F-8
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


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

GENERAL AND ADMINISTRATIVE EXPENSES: General and administrative expenses are
reported net of amounts allocated to working interest owners of the oil and gas
properties operated by the Company and net of amounts capitalized pursuant to
the full cost method of accounting.

USE OF ESTIMATES: The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of America
requires the use of estimates and assumptions that affect the amounts reported.
The actual results could differ from those estimates, including useful lives of
property and equipment and oil and gas reserve quantities.

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

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

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

                                                      2002             2003
                                                  -------------   -------------
    Options excluded from dilution calculation       140,000          64,000
    Range of exercise prices                      $3.50 - $8.00   $3.50 - $8.00
    Weighted average exercise price                   $5.65           $6.00


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

                                       F-9
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


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

Stock option activity for the year ended December 31, 2003 and 2002 is as
follows:
                                                                     WEIGHTED
                                                    NUMBER OF         AVERAGE
                                                     SHARES       EXERCISE PRICE
                                                  -------------   -------------
Balance as of December 31, 2001                         150,000   $        5.72
     Granted                                             13,000            3.50
     Exercised                                               --              --
     Forfeited                                           23,000   $        4.42
     Expired                                                 --              --
                                                  -------------   -------------
Balance as of December 31, 2002                         140,000   $        5.65
     Granted                                            100,000            1.00
     Exercised                                          (25,000)           1.00
     Forfeited                                          (76,000)           5.62
     Expired                                                 --              --
                                                  -------------   -------------
Balance as of December 31, 2003                         139,000   $        3.16
                                                  -------------   -------------

At December 31, 2003, the range of exercise prices and weighted-average
remaining contractual life of outstanding options was $1.00 to $8.00 and ten
years, respectively.

At December 31, 2003, the number of options exercisable was 114,000 and the
weighted-average exercise price of those options was $3.63.

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

                                                       2002            2003
                                                  -------------   -------------
Net (loss) earnings as reported                   $    (445,800)  $     535,001

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

Deduct: Pro forma stock-based compensation,
        net of tax                                     (208,387)        (79,081)
                                                  -------------   -------------
Pro forma net (loss) earnings                          (654,187)        485,721
                                                  =============   =============

For 2002, fair value was determined using the Black-Scholes option pricing model
with the following assumptions: expected dividend yield of 0%, risk-free
interest rate of 1.73%, expected volatility of 1.31%, and an expected term of 10
years.

COMMITMENTS AND CONTINGENCIES: Liabilities for loss contingencies arising from
claims, assessments, litigation, or other sources are recorded when it is
probable that a liability has been incurred and the amount can be reasonably
estimated.
                                      F-10
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


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

RECLASSIFICATIONS: Certain prior year balances have been reclassified to conform
to the current year presentation.

SEGMENT INFORMATION: GMX manages its business by country, which results in one
operating segment during each of the years ended December 31, 2003 and 2002.

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

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

                                                    YEAR ENDED
                                                DECEMBER 31, 2003
                                                -----------------
Beginning of the period                         $              --
Initial adoption entry                                    281,516
Liabilities incurred in the current period                     --
Liabilities settled in the current period                      --
Accretion expense                                          22,521
                                                -----------------
End of the period                               $         304,037
                                                =================

The pro forma effects on prior periods were not material.


                                      F-11
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


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

In December 2003, the FASB issued FASB Interpretation No. 46 (revised December
2003), Consolidation of Variable Interest Entities, which addresses how a
business enterprise should evaluate whether it has a controlling financial
interest in an entity through means other than voting rights and accordingly
should consolidate the entity. FIN 46R replaces FASB Interpretation No. 46,
Consolidation of Variable Interest Entities, which was issued in January 2003.
The Company will be required to apply FIN 46R to variable interests in VIEs
created after December 31, 2003. For variable interests in VIEs created before
January 1, 2004, the Interpretation will be applied beginning on January 1,
2005. For any VIEs that must be consolidated under FIN 46R that were created
before January 1, 2004, the assets, liabilities and noncontrolling interests of
the VIE initially would be measured at their carrying amounts with any
difference between the net amount added to the balance sheet and any previously
recognized interest being recognized as the cumulative effect of an accounting
change. If determining the carrying amounts is not practicable, fair value at
the date FIN 46R first applies may be used to measure the assets, liabilities
and noncontrolling interest of the VIE. The Company anticipates that this
standard will not have an impact on the Company's financial statements because
it does not own any interests in variable interest entities.

SFAS Statement of 150, Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity, ("SFAS 150") was issued in May,
2003. SFAS 150 establishes standards for the classification and measurement of
certain financial instruments with characteristics of both liabilities and
equity. SFAS 150 also includes required disclosures for financial instruments
within its scope. SFAS 150 was effective for instruments entered into or
modified after May 31, 2003 and otherwise will be effective as of January 1,
2004, except for mandatorily redeemable financial instruments. For certain
mandatorily financial instruments, FSAS 150 will be effective on January 1,
2005. The effective date has been deferred indefinitely for certain other types
of mandatorily redeemable financial instruments. The Company currently does not
have any financial instruments that are within the scope of SFAS 150.

During 2003, a reporting issue arose regarding the application of certain
provisions of SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill
and Other Intangible Assets," to companies in the extractive industries,
including oil and gas companies. The issue is whether SFAS No. 142 requires
registrants to classify the costs of mineral rights associated with extracting
crude oil and natural gas as intangible assets in the balance sheet, apart from
other capitalized oil and gas property costs, and provide specific footnote
disclosures. The EITF has added the treatment of oil and gas mineral rights to
an upcoming agenda, which may result in a change in how GMX classifies these
assets. Historically, the Company has included the costs of mineral rights
associated with extracting crude oil and natural gas as a component of oil and
gas properties. If it is ultimately determined that SFAS No. 142 requires oil
and gas companies to classify costs of mineral rights associated with extracting
crude oil and natural gas as a separate intangible assets line item on the
balance sheet, net of amortization, the Company most likely

                                      F-12
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


would be required to reclassify certain amounts out of oil and gas properties
and into a separate intangible assets line item. The Company's cash flows and
results of operations would not be affected since such intangible assets would
continue to be depleted and assessed for impairment in accordance with existing
full cost accounting rules.

If it is ultimately determined that SFAS No. 142 requires oil and gas companies
to classify costs of mineral rights associated with extracting crude oil and
natural gas as a separate intangible assets line item on the balance sheet, the
Company believes that the amount of costs that may be required to be
reclassified would be less than $500,000. The Company does not believe the
classification of the costs of mineral rights associated with extracting oil and
gas as intangible assets would have any impact on compliance with covenants
under the Company's debt agreements.

NOTE B--PROPERTY AND EQUIPMENT

Property and equipment included the following:

                                                          DECEMBER 31,
                                                  ----------------------------
                                                      2002            2003
                                                  ------------    ------------
Oil and gas properties:
   Subject to amortization                        $ 31,710,171    $ 31,219,309
   Not subject to amortization:
      Acquired in 2003                                      --          57,565
      Acquired in 2002                                  76,829          76,829
      Acquired in 2001                                 853,258         853,258
      Acquired in 2000                                  93,195          93,195
      Acquired in 1999                                      --              --
      Acquired in 1998                                 148,940         148,940
   Accumulated depreciation, depletion, and         (3,522,584)     (4,930,779)
   amortization
                                                  ------------    ------------
      Net oil and gas properties                    29,359,809      27,518,317
                                                  ------------    ------------
Other property and equipment                         3,200,345       3,200,345
Less accumulated depreciation                         (656,572)       (991,889)
                                                  ------------    ------------

      Net other property and equipment               2,543,773       2,208,456
                                                  ------------    ------------
      Property and equipment, net of accumulated
      Depreciation, depletion, and amortization   $ 31,903,582    $ 29,726,773
                                                  ============    ============

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


                                      F-13
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


                                                      FOR THE YEAR ENDED
                                                          DECEMBER 31,
                                                  ----------------------------
                                                      2002            2003
                                                  ------------    ------------
Depreciation, depletion, and amortization of
   oil and gas properties                         $  1,557,930    $  1,214,361
Depreciation of other property and equipment           344,046         335,317
                                                  ------------    ------------
      Total                                       $  1,901,976    $  1,549,678
                                                  ============    ============


NOTE C--LONG-TERM DEBT
                                                          DECEMBER 31,
                                                  ----------------------------
                                                      2002            2003
                                                  ------------    ------------
Note payable to bank, bearing a variable
interest rate (4.75% and 5.25% as of December
31, 2001 and 2002, respectively) collateralized
by producing oil and gas properties               $  8,100,000    $  6,690,000
                                                  ------------    ------------
                                                     8,100,000       6,690,000
      Current portion                               (8,100,000)     (1,060,000)
                                                  ------------    ------------
           Long Term                              $         --    $  5,630,000
                                                  ============    ============


2000 CREDIT FACILITY

On October 31, 2000, the Company entered into a new secured credit facility,
which replaced a prior credit facility. The new credit facility provides for a
line of credit of up to $15,000,000 (the "Commitment"), subject to a borrowing
base which is based on a periodic evaluation of oil and gas reserves which is
reduced monthly to account for production ("Borrowing Base"). The amount of
credit available at any one time under the credit facility is the lesser of the
Borrowing Base or the amount of the Commitment. Borrowings bear interest at the
prime rate plus 1%. The credit facility requires payment of an annual facility
fee equal to 1/2% on the unused amount of the Borrowing Base. The Company is
obligated to make principal payments if the amount outstanding would exceed the
Borrowing Base. Borrowings under the credit agreement are secured by
substantially all of the Company's oil and gas properties. The amount of this
Borrowing Base has been adjusted from time to time. The credit facility has been
amended on several occasions to waive non-payment default or to extend the
maturity. The credit facility matured in May 2003 and we remained in default
under the facility until August 2003 when the credit facility was amended to
extend the maturity date of the promissory note from May 1, 2003 to new maturity
date of March 1, 2004. On March 15, 2004, the bank approved an extension of the
existing credit facility with the following amended terms: New maturity date of
September 1, 2004, Borrowing Base of $6,310,000, monthly commitment reduction of
$90,000 and all other terms in the existing credit agreement to remain
unchanged. At December 31, 2003, the Company had borrowed $6,690, 000 under the
credit facility.

The credit facility contains various affirmative and restrictive covenants.
These covenants, among other things, prohibit additional indebtedness, sales of
assets, mergers and consolidations,

                                      F-14
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


dividends and distributions, changes in management and require the maintenance
of various financial ratios. See Note L.

SUBORDINATED NOTES

In January 2004, the Company raised $1 million from the sale of 11% senior
subordinated notes due January 31, 2007 and five-year detachable warrants to
purchase 175,000 shares of common stock for $1.50 per share. The price of the
Company's common shares as of that date was $3.16. For accounting purposes, the
fair value of the in-the-money warrants will increase the effective interest
rate over the term of the notes. In connection with this transaction, the lender
under the Company's bank credit facility agreed to the Company's incurrence of
additional debt and entered into an intercreditor and subordination agreement
with the noteholders pursuant to which the noteholders subordinated their rights
to payment to the rights of the bank under the credit facility. Principal
reductions of $100,000 per year on the subordinated notes are permitted in 2005
and 2006 subject to certain conditions being met under the terms of the credit
facility agreements.

The Company is obligated to register the warrants and underlying shares of
common stock under the Securities Act of 1933 on or before June 30, 2004 in
order to permit the holders to sell the warrants and underlying shares without
restrictions. If the Company fails to effect or maintain such registration, it
is obligated to issue additional warrants at the rate of 10,000 warrants per
month such failure exists.

NOTE D--INCOME TAXES

Intangible development costs are expensed for income tax reporting purposes,
whereas they are capitalized and amortized for financial statement purposes.
Lease and well equipment and other property and equipment are depreciated for
income tax reporting purposes using accelerated methods. Deferred income taxes
are provided on these temporary differences to the extent that income taxes
which otherwise would have been payable are reduced. Deferred income tax assets
also are recognized for operating losses that are available to offset future
income taxes.

At December 31, 2003, the Company had the following carryforwards available to
reduce future income taxes:

Federal                                           $ 21,141,000
States                                               7,234,000
Statutory depletion                                  2,575,000

The net operating loss and statutory depletion carryforward amounts shown above
have been utilized for financial purposes to offset existing deferred tax
liabilities. The net operating loss carryforwards expire from 2018 to 2021.
Statutory depletion carryforwards do not expire.

As of December 31, 2003, the Company's deferred tax liability of $7,896,000 was
primarily associated with the difference between financial carrying value of oil
and gas properties and the

                                      F-15
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


associated tax basis. As of the same date, the Company's gross deferred tax
asset of $8,498,000 was primarily the result of the Company's net operating loss
and statutory depletion carryforwards. As of December 31, 2003, the Company
recognized a valuation allowance of $602,000. Management of the Company
determined that based upon current taxable income and financial conditions that
it is not more likely than not that the Company will be able to utilize all of
its net operating loss carryforwards prior to their expiration.

                                                           DECEMBER 31,
                                                  ----------------------------
                                                      2002            2003
                                                  ------------    ------------
Deferred tax assets:
      Net operating loss carry forwards              7,712,000       7,622,000
      Statutory depletion carry forwards               638,000         876,000
                                                  ------------    ------------
                 Total                               8,350,000       8,498,000
                                                  ------------    ------------
Deferred tax liability:
      Property, plant and equipment                 (8,060,000)     (7,896,000)
      Valuation allowance                             (290,000)       (602,000)
                                                  ------------    ------------
                 Total                              (8,350,000)     (8,498,000)
                                                  ------------    ------------
Net deferred tax asset                                      --              --
                                                  ============    ============


As of December 31, 2002, the Company's deferred tax liability of $8,060,000 was
primarily associated with the difference between financial carrying value of oil
and gas properties and the associated tax basis. As of the same date, the
Company's deferred tax asset of $8,350,000 was primarily the result of the
Company's net operating loss and statutory depletion carryforwards.

Total income tax expense for the respective years differed from the amounts
computed by applying the U.S. federal tax rate to earnings before income taxes
as a result of the following:

                                                      FOR THE YEAR ENDED
                                                          DECEMBER 31,
                                                  ----------------------------
                                                      2002            2003
                                                  ------------    ------------
U.S. statutory tax rate                                     34%             34%
Statutory depletion                                        (34)            (93)
Change in valuation allowance                               41              58
Other                                                       (4)              1
                                                  ------------    ------------
Effective income tax rate                                   37              --
                                                  ============    ============

NOTE E--COMMITMENTS AND CONTINGENCIES

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

                                      F-16
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


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, 2003.

Year Ending December 31:

2004                                              $    162,129
2005                                                   110,091
2006                                                   110,091
                                                  ------------
      Total                                       $    382,311
                                                  ============

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

2002                                              $     97,298
2003                                                   195,468


NOTE F--SHAREHOLDERS' EQUITY

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

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

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

On April 15, 2003, the Company granted an option to a consultant to purchase
100,000 shares of common stock at a price of $1.00 per share. Options on 25,000
shares were vested on the date of

                                      F-17
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


the grant and the balance vest 25,000 on July 15, 2003, 25,000 on October 15,
2003 and 25,000 on January 1, 2004. The fair value of the stock options granted
was recognized in 2003.

In addition on April 5, 2004, the Company closed a private placement of 200,000
shares of common stock for $1,000,000 with an investor. Proceeds of the
transaction will be used for general corporate purposes.

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 expired on
February 12, 2003. The Company used a portion of the proceeds of the offering to
repay $427,500 of loans from shareholders.

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

NOTE G--MAJOR CUSTOMERS

Sales to individual customers constituting 10% or more of total oil and gas
sales for each of the years ended December 31, 2002 and 2003 were as follows:

                                                            2002           2003
                                                            ----           ----
      Teppco Crude                                           95%            99%
      CrossTex Energy Services, Inc.                         77%            83%


NOTE H--DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

During 2002 and 2003, the Company utilized swap arrangements to hedge a portion
of its exposure to price volatility from producing natural gas. Each swap
arrangement established a price above which the Company paid the counterparty
and below which the Company was paid. Results from commodity hedging
transactions are reflected in gas sales.

The Company entered into natural gas price swaps that initiated in March 2002
and expired in February 2003. These agreements relate to 50,000 and 40,000 mmbtu
whereby the Company will receive a fixed price of $2.66 and $2.67 per mmbtu,
respectively and pay the counterparty an index price. Payments by the Company in
2002 totaled $652,100 and $438,400 in 2003.

There were no outstanding financial instruments as of December 31, 2003.

                                      F-18
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


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

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

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

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

GMX does not hold or issue derivative instruments for trading purposes. All of
GMX's commodity price financial swaps in place at January 1, 2003 were
designated as cash flow hedges. Changes in the fair value of these derivatives
were reported in "Accumulated other comprehensive income." These amounts were
reclassified to oil and gas sales when the forecasted transaction took place.


NOTE I--CONCENTRATION OF CREDIT RISK

The Company maintains its cash in bank deposit accounts which, at times, may
exceed federal insured limits. The Company has not experienced any losses in
such accounts and believes it is not exposed to any significant risk.


NOTE J--OIL AND GAS OPERATIONS (UNAUDITED)

Capitalized costs related to the Company's oil and gas producing activities as
of December 31, 2002 and 2003 are:

                                      F-19
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


                                                      2002            2003
                                                  ------------    ------------
Unproved properties                               $  1,171,722    $  1,229,787
Producing properties                                31,710,171      31,219,309
                                                  ------------    ------------
                                                    32,881,893      32,449,096
Less accumulated depreciation,
 depletion, and Amortization                        (3,522,584)     (4,788,779)
                                                  ------------    ------------
      Net capitalized costs                       $ 29,359,309    $ 27,660,317
                                                  ============    ============

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

Costs incurred in oil and gas property acquisitions, exploration, and
development activities in 2002 and 2003 are as follows:

                                                      2002            2003
                                                  ------------    ------------
Property acquisition costs - proved               $    120,157    $     57,575
Property acquisition costs - unproved                   84,672           5,212
Development costs                                    2,812,876         175,840
                                                  ------------    ------------
                                                  $  3,017,705    $    238,627
                                                  ============    ============

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 2002 and 2003 include revenues and
expenses associated directly with oil and gas producing activities.

                                                      2002            2003
                                                  ------------    ------------
Oil and gas sales                                 $  5,970,792    $  5,367,370
Production costs                                     1,707,307       1,211,582
Depreciation, depletion and amortization             1,557,930       1,214,779
Income tax expense                                     665,000         733,670
                                                  ------------    ------------
Results of operations for oil and gas
  producing activities                            $  2,040,555    $  2,207,339
                                                  ============    ============

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

The oil and gas reserve quantity information presented below is unaudited and is
based upon reports prepared by independent petroleum engineers. The information
is presented in accordance with regulations prescribed by the Securities and
Exchange Commission. The

                                      F-20
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


Company emphasizes that reserve estimates are inherently imprecise. The
Company's reserve estimates were estimated by performance methods, volumetric
methods, and comparisons with analogous wells, where applicable. The reserves
estimated by the performance method utilized extrapolations of historical
production data. Reserves were estimated by the volumetric or analogous methods
in cases where the historical production data was insufficient to establish a
definitive trend. Accordingly, these estimates are expected to change, and such
changes could be material and occur in the near term as future information
becomes available.

Proved oil and gas reserves represent the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are those expected to be recovered through
existing wells with existing equipment and operating methods. As of December 31,
2002 and 2003, all of the Company's oil and gas reserves were located in the
United States.
                                                       OIL            GAS
                                                     (MBBLS)         (MMCF)
                                                  ============    ============
DECEMBER 31, 2002
  Proved reserves, beginning of period                   3,862          68,611
  Extensions, discoveries, and other additions              --              --
  Production                                               (70)         (1,639)
  Sale of reserves in-place                             (1,218)         (2,263)
  Revisions of previous estimates                         (910)         (8,027)
                                                  ------------    ------------
  Proved reserves, end of period                         1,664         (56,682)
                                                  ============    ============
  Proved developed reserves:
      Beginning of period                                1,018          15,352
                                                  ============    ============
      End of period                                        604          16,501
                                                  ============    ============
DECEMBER 31, 2003
  Proved reserves, beginning of period                   1,664          56,682
  Extensions, discoveries, and other additions              --              --
  Production                                               (35)           (917)
  Sale of reserves in-place                               (251)        (11,414)
  Revisions of previous estimates                          (55)            678
                                                  ------------    ------------
  Proved reserves, end of period                         1,323          45,029
                                                  ============    ============
  Proved developed reserves:
      Beginning of period                                  604          16,501
                                                  ============    ============
      End of period                                        568          18,277
                                                  ============    ============

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-21
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


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

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

                                                  DECEMBER 31,    DECEMBER 31,
                                                      2002            2003
                                                  ------------    ------------
                                                 (IN THOUSANDS)  (IN THOUSANDS)

Future cash inflows                               $    294,669    $    300,514
Future production costs                                (68,815)        (77,608)
Future development costs                               (39,518)        (44,557)
Future income tax provisions                           (60,799)        (58,158)
                                                  ------------    ------------

  Net future cash inflows                              125,537         120,191
Less effect of a 10% discount factor                   (71,225)        (72,216)
                                                  ------------    ------------
  Standardized measure of discounted
    future net cash flows                         $     54,312    $     47,975
                                                  ============    ============

Oil and condensate prices were based on an equivalent base price of $32.52 per
barrel for benchmark posted West Texas Intermediate Crude Oil at closing on
December 31, 2003. 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 $32.04 per barrel. Natural gas prices were based on an equivalent base price
of $6.187 per million British thermal unit (mmbtu) for the composite Henry Hub
Spot Market benchmark price at closing on December 31, 2003. Adjustments to the
base price were made to each lease to adjust the base price for quality,
contractual agreements, and regional price variations. The average natural gas
price used in the reserve estimates was $5.73 per mmbtu. Future income tax
expenses are computed by applying the appropriate statutory rates to the future
pre-tax net cash flows relating to proved reserves, net of the tax basis of the
properties involved giving effect to permanent differences, tax credits, and
allowances relating to proved oil and gas reserves.

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




                                      F-22
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2002 AND 2003


                                                  DECEMBER 31,    DECEMBER 31,
                                                      2002            2003
                                                  ------------    ------------
Standardized measure, beginning of year                 48,524          54,312
Sales of oil and gas, net of production costs           (2,508)         (4,156)
Net changes in prices and production costs              51,708          11,782
Extensions and discoveries, net of future
  development costs                                         --              --
Development costs that reduced future
  development costs                                      2,091              --
Revisions of quantity estimates                        (20,447)            646
Sales of reserves in place                             (15,192)        (16,434)
Accretion of discount                                    7,095           8,061
Other                                                  (13,084)         (9,322)
Net changes in income taxes                             (3,875)          3,086
                                                  ------------    ------------
Standardized measure, end of year                       54,312          47,975
                                                  ============    ============


NOTE L--MANAGEMENT'S PLANS

The Company reached a drilling arrangement with Penn Virginia Oil & Gas
Corporation ("PVOG") in December of 2003 relating to the joint development of
its east Texas properties. As a result of that agreement, the Company has a 20%
carried interest in the first five wells that are drilled in Phase I. The
Company then has the option, but not the obligation, to participate in any
remaining Phase I wells for a 30% interest. As a result of this agreement, the
Company has reduced its cost and ownership related to the development of these
wells. In addition, subsequent to December 31, 2003, the Company has raised
$1,000,000 of subordinated debt and $1,000,000 of equity to date in 2004 for
recompletion and other corporate activities. As a result of the increased 2004
production levels and, to a lesser extent, increased commodity prices, the
Company has been able to extend the maturity of its existing credit facility to
September 1, 2004. The Company has also received term sheets from other lenders
to refinance the credit facility, increase the borrowing base, and extend the
maturity date. On April 14, 2004, the Company received a formal commitment from
its current lender to extend the maturity date to September 1, 2005, subject to
the Company's applying the proceeds of its recent common stock private placement
to prepayment of the 11% subordinated notes on or before May 14, 2004. As a
result, the Company has reclassified a portion of the credit facility as a
long-term liability.  The Company will continue to evaluate the other lenders'
terms to maximize its flexibility before accepting this proposal. The Company is
also considering additional issuances of subordinated debt or equity to provide
additional funds for drilling plans. If the Company is unable to raise
additional subordinated debt or equity and unable to increase or extend its
credit facility beyond September 2005, the Company would be unlikely to be able
to participate in additional drilling.


                                      F-23
<PAGE>
                                  EXHIBIT INDEX
                                  -------------


EXHIBIT
  NO.      DESCRIPTION OF EXHIBIT
-------    ----------------------

3.1        Amended and Restated Certificate of Incorporation of GMX RESOURCES
           INC. (Incorporated by reference to Exhibit 3.1 to the Registration
           Statement on Form SB-2, File No. 333-49328)

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

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

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

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

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

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

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

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

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

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

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

10.4(e)    Sixth Amendment to Credit Agreement dated as of March 1, 2004

10.4(f)    Letter dated April 14, 2004 from Local Oklahoma Bank.

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

10.6       Participation Agreement dated December 29, 2003 by and among Penn
           Virginia Oil & Gas Company, the Company and its wholly owned
           subsidiaries (Incorporated by reference to Exhibit 10.1 to Current
           Report on Form 8-K dated December 29, 2003

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

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

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

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

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

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

14         Code of Business Conduct and Ethics

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

23.1       Consent of KPMG LLP

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

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

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

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

*          Management contracts or compensatory plan.