<PAGE>

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                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                                  FORM 10-K/A
              ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                        SECURITIES EXCHANGE ACT OF 1934

                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

                        COMMISSION FILE NUMBER: 0-22149

                           EDGE PETROLEUM CORPORATION
             (Exact name of Registrant as specified in its charter)

<Table>
<S>                                            <C>
                   DELAWARE                                      76-0511037
(State or other jurisdiction of incorporation                 (I.R.S. Employer
               or organization)                             Identification No.)

    1301 TRAVIS, SUITE 2000 HOUSTON, TEXAS                         77002
   (Address of principal executive offices)                      (Zip code)
</Table>

                                  713-654-8960
              (Registrant's telephone number including area code)

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

          SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
                                      NONE

          SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
                     COMMON STOCK, PAR VALUE $.01 PER SHARE

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

     Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.  Yes [X]     No [ ]

     Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not 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-K or any amendment to this
Form 10-K.  Yes [ ]     No [X]

     Indicate by check mark whether the registrant is an accelerated
filer.  Yes [ ]     No [X]

     As of June 28, 2002, the aggregate market value of the voting stock held by
non-affiliates of the registrant was $50.6 million (based on a value of $5.38
per share, the closing price of the Common Stock as quoted by NASDAQ National
Market on such date). As of March 14, 2003, 9,465,734 shares of Common Stock,
par value $.01 per share, were outstanding.

                      DOCUMENTS INCORPORATED BY REFERENCE

     Portions of the definitive proxy statement for the registrant's 2003 Annual
Meeting of Shareholders, to be filed pursuant to Regulation 14A under the
Securities Exchange Act of 1934, are incorporated by reference into Part III of
this report.
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>

     This Amendment No. 1 on Form 10-K/A is being filed to amend the annual
report on Form 10-K of Edge Petroleum Corporation (the "Company"). The purpose
of this Amendment is to amend Items 1 and 2. Business and Properties for
revisions to disclosures and clarification of forward-looking information and
risk factors, Item 4. Submission of Matters to A Vote of Security Holders to
provide clarification of experience for certain significant employees as well as
ages for all significant employees, Item 6. Selected Financial Data for certain
presentational changes, Part III for supplemental information and typographical
errors, Part IV for typographical errors and to clarify exhibit index
references, Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations for additional disclosure pertaining to recent
developments and other presentational changes and Item 8. Consolidated Financial
Statements for additional disclosure pertaining to recent developments and other
presentational changes. Except for the foregoing, no attempt has been made in
this Form 10K/A to modify or update other disclosures as presented in the
original Form 10K.
<PAGE>

                               TABLE OF CONTENTS

<Table>
<Caption>
                                                                              PAGE
                                                                              ----
<S>             <C>                                                           <C>
                                      PART I
Items 1 and 2.  Business and Properties.....................................    2
Item 3.         Legal Proceedings...........................................   22
Item 4.         Submission of Matters to a Vote of Security Holders.........   23

                                     PART II
Item 5.         Market for Registrant's Common Equity and Related
                Stockholder Matters.........................................   25
Item 6.         Selected Financial Data.....................................   26
Item 7.         Management's Discussion and Analysis of Financial Condition
                and Results of Operations...................................   28
Item 7A.        Qualitative and Quantitative Disclosures About Market
                Risk........................................................   41
Item 8.         Financial Statements and Supplementary Data.................   41
Item 9.         Changes in and Disagreements with Accountants on Accounting
                and Financial Disclosures...................................   41

                                     PART III
Item 10.        Directors and Executive Officers of the Registrant..........   42
Item 11.        Executive Compensation......................................   42
Item 12.        Security Ownership of Certain Beneficial Owners and
                Management and Related Stockholder Matters..................   42
Item 13.        Certain Relationships and Related Transactions..............   43
Item 14.        Controls and Procedures.....................................   43

                                     PART IV
Item 15.        Exhibits, Financial Statement Schedules, and Reports on Form
                8-K.........................................................   43
</Table>

                                        1
<PAGE>

                           EDGE PETROLEUM CORPORATION

     Unless otherwise indicated by the context, references herein to the
"Company" or "Edge" mean Edge Petroleum Corporation, a Delaware corporation, and
its corporate and partnership subsidiaries and predecessors. Certain terms used
herein relating to the oil and natural gas industry are defined in ITEMS 1 AND
2. -- "BUSINESS AND PROPERTIES -- CERTAIN DEFINITIONS."

                                     PART I

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

OVERVIEW

     Edge Petroleum Corporation is an independent oil and natural gas company
engaged in the exploration, development, acquisition and production of crude oil
and natural gas properties in the United States. At year-end 2002, our net
proved reserves were 49.0 Bcfe, comprised of 35.0 billion cubic feet of natural
gas, 810 thousand barrels of oil and 1,532 thousand barrels of plant products.
Natural gas and natural gas liquids accounted for approximately 90% of those
proved reserves. About 68% of total proved reserves were developed as of
year-end and they were all located onshore, in the United States.

     Edge was founded in 1983 as a private company and went public in 1997
through an initial public offering. We have evolved over time from a prospect
generation organization focused solely on high-risk, high-reward exploration
projects to a team-driven organization focused on a balanced program of
exploration, exploitation, development and acquisition of oil and natural gas
properties. Following a top-level management change in late 1998, a more
disciplined style of business planning and management was integrated into our
technology-driven drilling activities. We believe these changes in our strategy
and business discipline will result in continued growth in reserves, production
and financial strength.

STRATEGY

     Our strategy for growth has evolved over the past several years and is
based upon the following main elements:

     - reserve growth through the drilling of a balanced portfolio of prospects

     - balancing exploration risk with the acquisition and exploitation of
       existing properties that we believe have upside potential

     - focusing on specific geographic areas where we believe we can add value

     - integration of the latest technological advances into our exploration,
       drilling and production operations

     - maintaining a conservative financial structure and controlling our cost
       structure

     - using equity ownership and performance-based compensation programs to
       attract and retain a high-quality workforce.

DRILLING PROGRAM

     During 2002, Edge's drilling program was focused in two primary areas. We
drilled 13 wells in 2002 with 11 completed as productive for an 85% apparent
success rate. Our average well cost increased substantially in 2002 as we took
larger working interest in more costly wells. This drilling program, along with
a small acquisition and positive revisions related to performance, helped to
enable us to replace 161% of our production in 2002 and grow our year-end
reserves by nine percent. We expect to drill 20 to 25 wells in 2003 with less
concentration of risk in any single well.

BALANCE

     In 2002, 83% of our reserve growth came from our drilling activity and 17%
came from acquisitions and revisions. We seek acquisitions of proven properties
that typically have exploration or exploitation upside potential. We primarily
seek properties in our existing core areas, or as a means to establish new core
areas.
                                        2
<PAGE>

We spent considerable effort in 2002 on acquisitions. We continue to work
diligently to identify and evaluate acquisition opportunities with the goal of
identifying those that we believe would fit our strategic plan and add
shareholder value.

     We believe our low and moderate-risk drilling program has the potential to
replace our production and to provide moderate reserve growth while our
higher-risk drilling program and acquisitions have the potential to rapidly
accelerate our growth as well as add to future drilling opportunities.

GEOGRAPHIC FOCUS

     We believe geographic focus is a critical element of success. Long-term
success requires detailed knowledge of both geologic and geophysical attributes,
as well as operating conditions in our chosen areas. As a result, we focus on a
select number of geographic areas where our experience and strengths can be
applied with a significant influence on the outcome. We believe this focus will
allow us to manage a growing asset base while controlling increases in staffing
and allow us to add value to additional properties while controlling incremental
costs.

TECHNOLOGY

     We use advanced technologies as risk reduction tools in our exploration and
development activities. Advanced visualization and data analysis techniques and
advanced processing techniques combined with our more traditional sub-surface
interpretation techniques allow our team of technical personnel to more easily
identify features, structural details and fluid contacts, that could be
overlooked using less sophisticated data interpretation techniques. As of
December 31, 2002, we had rights to approximately 2,487 square miles of 3D
seismic data. Of that amount, we had approximately 1,585 square miles in Texas,
709 square miles in Louisiana, 55 square miles in Montana and 138 square miles
in Mississippi and Alabama.

FINANCIAL STRUCTURE

     We believe that a conservative financial structure is crucial to
consistent, positive financial results, management of cyclical swings in our
industry and the ability to move quickly to take advantage of acquisitions and
attractive drilling opportunities. At December 31, 2002, our debt to total
capital ratio was 26 percent. We try to fund most of our ongoing capital
expenditures from cash flow from operations, reserving our debt capacity for
potential investment opportunities that we believe can profitably add to our
program. Part of a sound financial structure is constant attention to costs,
both operating and overhead costs. Over the past three years, we have worked
diligently to control our operating costs, significantly reduced our overhead
costs and instituted a formal, disciplined capital budgeting process.

EQUITY OWNERSHIP

     Following a management change in late 1998, we eliminated the previous
overriding royalty compensation system and replaced it with a system designed to
reward all employees through performance-based compensation that is competitive
with our peers and through equity ownership. As of March 14, 2003, our employees
and directors owned or had options to acquire an aggregate of about 20% of our
outstanding common stock.

OIL AND NATURAL GAS RESERVES

     The following table sets forth our estimated net proved oil and natural gas
reserves and the present value of estimated future pretax net cash flows related
to such reserves as of December 31, 2002. We engaged Ryder Scott Company ("Ryder
Scott") to estimate our net proved reserves, projected future production,
estimated future net revenue attributable to our proved reserves, and the
present value of such estimated future net revenue as of December 31, 2002.
Ryder Scott's estimates were based upon a review of production histories and
other geologic, economic, ownership and engineering data provided by us. In
estimating the reserve quantities that are economically recoverable, Ryder Scott
used year-end oil and natural gas prices in effect at December 31, 2002 and
estimated development and production costs that were in effect during December
2002 without giving effect to hedging activities. In accordance with
requirements of the Securities and Exchange Commission (the "Commission")
regulations, no price or cost escalation or reduction was
                                        3
<PAGE>

considered by Ryder Scott. For further information concerning Ryder Scott's
estimate of our proved reserves at December 31, 2002, see the reserve report
included as an exhibit to this Annual Report on Form 10-K (the "Ryder Scott
Report"). The present value of estimated future net revenues before income taxes
was prepared using constant prices as of the calculation date, discounted at 10%
per annum on a pretax basis, and is not intended to represent the current market
value of the estimated oil and natural gas reserves owned by us. For further
information concerning the present value of future net revenue from these proved
reserves, see Note 14 to our consolidated financial statements. See ITEMS 1 AND
2. -- "BUSINESS AND PROPERTIES -- FORWARD LOOKING INFORMATION AND RISK
FACTORS" -- The oil and natural gas reserve data included in or incorporated by
reference in this document are only estimates and may prove to be inaccurate.

<Table>
<Caption>
                                                           PROVED RESERVES
                                             --------------------------------------------
                                             DEVELOPED(1)   UNDEVELOPED(2)      TOTAL
                                             ------------   --------------   ------------
<S>                                          <C>            <C>              <C>
Oil and condensate (MBbls)(3)..............         1,510            832            2,342
Natural gas (MMcf).........................        24,234         10,746           34,980
  Total MMcfe..............................        33,293         15,740           49,033
Estimated future net revenue before income
  taxes....................................  $117,476,070    $53,366,852     $170,842,922
Present value of estimated future net
  revenue before income taxes (discounted
  10% annum)(4)............................  $ 79,126,129    $36,845,746     $115,971,875
</Table>

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

(1) Proved developed reserves are proved reserves that are expected to be
    recovered from existing wells with existing equipment and operating methods.

(2) Proved undeveloped reserves are proved reserves which are expected to be
    recovered from new wells on undrilled acreage or from existing wells where a
    relatively major expenditure is required for recompletion.

(3) Includes plant products.

(4) Estimated future net revenue represents estimated future gross revenue to be
    generated from the production of proved reserves, net of estimated future
    production and development costs, using year-end oil and natural gas prices
    in effect at December 31, 2002, which were $4.79 per Mcf of natural gas and
    $31.20 per Bbl of oil.

     The reserve data set forth herein represents estimates only. Reserve
engineering is a subjective process of estimating underground accumulations of
oil and natural gas that cannot be measured in an exact manner, and the accuracy
of any reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a result, estimates
made by different engineers often vary from one another. In addition, results of
drilling, testing and production subsequent to the date of an estimate may
justify revision of such estimates, and such revisions may be material.
Accordingly, reserve estimates are generally different from the quantities of
oil and natural gas that are ultimately recovered. Furthermore, the estimated
future net revenue from proved reserves and the present value thereof are based
upon certain assumptions, including future prices, production levels and costs
that may not prove correct.

     No estimates of proved reserves comparable to those included herein have
been included in reports to any federal agency other than the Commission.

     In accordance with Commission regulations, the Ryder Scott Report used
year-end oil and natural gas prices in effect at December 31, 2002. The prices
used in calculating the estimated future net revenue attributable to proved
reserves do not necessarily reflect market prices for oil and natural gas
production subsequent to December 31, 2002. There can be no assurance that all
of the proved reserves will be produced and sold within the periods indicated,
that the assumed prices will actually be realized for such production or that
existing contracts will be honored or judicially enforced.

                                        4
<PAGE>

OIL AND NATURAL GAS VOLUMES, PRICES AND OPERATING EXPENSE

     The following table sets forth certain information regarding production
volumes, average sales prices and average oil and natural gas operating expense
associated with our sale of oil and natural gas for the periods indicated.

<Table>
<Caption>
                                                             YEAR ENDED DECEMBER 31,
                                                             ------------------------
                                                              2002     2001     2000
                                                             ------   ------   ------
<S>                                                          <C>      <C>      <C>
PRODUCTION:
  Oil and condensate (MBbls)...............................     120      116       97
  Natural gas liquids (MBbls)..............................     161       46       77
  Natural gas (MMcf).......................................   5,266    6,199    5,206
  Natural gas equivalent (MMcfe)...........................   6,951    7,167    6,249
AVERAGE SALES PRICE:
  Oil and condensate ($ per Bbl)(1)........................  $22.88   $23.94   $26.16
  Natural gas liquids ($ per Bbl)..........................  $10.31   $17.74   $16.37
  Natural gas ($ per Mcf)(1)...............................  $ 3.14   $ 4.23   $ 3.84
  Natural gas equivalent ($ per Mcfe)(1)...................  $ 3.01   $ 4.16   $ 3.80
AVERAGE OIL AND NATURAL GAS OPERATINGEXPENSES INCLUDING
  PRODUCTION AND ADVALOREM TAXES ($ PER MCFE)(2)...........  $ 0.55   $ 0.70   $ 0.63
</Table>

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

(1) Includes the effect of hedging activity.

(2) Includes direct lifting costs (labor, repairs and maintenance, materials and
    supplies), expensed workover costs and the administrative costs of
    production offices, insurance and production and ad valorem taxes.

FINDING AND DEVELOPMENT COSTS

     We incurred total exploration, development and acquisition costs of
approximately $19.6 million for the year ended December 31, 2002 that added 11.2
Bcfe, net to our interest, of proved reserves. Our average finding and
development cost was $1.75 per Mcfe for 2002. For the three most recent years,
the total of these costs was $58.9 million adding 46.6 Bcfe of proved reserves
for an average finding and development cost of $1.26 per Mcfe.

EXPLORATION, DEVELOPMENT AND ACQUISITION CAPITAL EXPENDITURES

     The following table sets forth certain information regarding the total
costs incurred associated with exploration, development and acquisition
activities.

<Table>
<Caption>
                                                            YEAR ENDED DECEMBER 31,
                                                          ---------------------------
                                                           2002      2001      2000
                                                          -------   -------   -------
                                                                (IN THOUSANDS)
<S>                                                       <C>       <C>       <C>
Acquisition Cost:
  Unproved properties...................................  $ 5,466   $ 7,052   $ 4,220
  Proved properties.....................................    1,369     5,695        --
Exploration costs.......................................    4,725    11,046     2,707
Development costs.......................................    7,927     4,823     3,766
                                                          -------   -------   -------
  Total costs incurred..................................  $19,487   $28,616   $10,693
                                                          =======   =======   =======
</Table>

     Net costs incurred excludes sales of proved oil and natural gas properties
which are accounted for as adjustments of capitalized costs with no gain or loss
recognized, unless such adjustments would significantly alter the relationship
between capitalized costs and proved reserves.

                                        5
<PAGE>

DRILLING ACTIVITY

     The following table sets forth our drilling activity for the three years
ended December 31, 2002. In the table, "gross" refers to the total wells in
which we have a working interest and "net" refers to gross wells multiplied by
our working interest therein.

<Table>
<Caption>
                                                    FOR THE YEAR ENDED DECEMBER 31,
                                              -------------------------------------------
                                                  2002           2001           2000
                                              ------------   ------------   -------------
                                              GROSS   NET    GROSS   NET    GROSS    NET
                                              -----   ----   -----   ----   -----   -----
<S>                                           <C>     <C>    <C>     <C>    <C>     <C>
EXPLORATORY:
  Productive................................    4     3.45    11     4.95    19      7.90
  Non-productive............................   --       --     3     1.16     2      1.43
                                               --     ----    --     ----    --     -----
     Total..................................    4     3.45    14     6.11    21      9.33
                                               --     ----    --     ----    --     -----
DEVELOPMENT:
  Productive................................    7     2.69     6     2.13     5      1.16
  Non-productive............................    2     0.54     2     0.96    --        --
                                               --     ----    --     ----    --     -----
     Total..................................    9     3.23     8     3.09     5      1.16
                                               --     ----    --     ----    --     -----
GRAND TOTAL.................................   13     6.68    22     9.20    26     10.49
                                               ==     ====    ==     ====    ==     =====
</Table>

PRODUCTIVE WELLS

     The following table sets forth the number of productive oil and natural gas
wells in which we owned an interest as of December 31, 2002.

<Table>
<Caption>
                                              COMPANY-
                                              OPERATED      NON-OPERATED      TOTAL(1)
                                            -------------   -------------   -------------
                                            GROSS    NET    GROSS    NET    GROSS    NET
                                            -----   -----   -----   -----   -----   -----
<S>                                         <C>     <C>     <C>     <C>     <C>     <C>
Oil.......................................   11      5.34     56    12.62     67    17.96
Natural gas...............................   51     39.96     94    23.61    145    63.57
                                             --     -----    ---    -----    ---    -----
  Total...................................   62     45.30    150    36.23    212    81.53
                                             ==     =====    ===    =====    ===    =====
</Table>

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

(1) Includes 75 gross wells shut-in (23.68 net).

ACREAGE DATA

     The following table sets forth certain information regarding our developed
and undeveloped lease acreage as of December 31, 2002. Developed acres refer to
acreage within producing units and undeveloped acres refer to acreage that has
not been placed in producing units.

<Table>
<Caption>
                                   DEVELOPED ACRES   UNDEVELOPED ACRES        TOTAL
                                   ---------------   -----------------   ----------------
                                   GROSS     NET      GROSS      NET      GROSS     NET
                                   ------   ------   -------   -------   -------   ------
<S>                                <C>      <C>      <C>       <C>       <C>       <C>
Texas............................  62,681   22,899   11,526     4,489     74,207   27,388
Louisiana........................   3,596      790    7,977     3,230     11,573    4,020
Mississippi......................   2,660       87      184        36      2,844      123
Alabama..........................     536        3       40         1        576        4
Montana..........................      --       --   67,642    30,568     67,642   30,568
                                   ------   ------   ------    ------    -------   ------
  Total..........................  69,473   23,779   87,369    38,324    156,842   62,103
                                   ======   ======   ======    ======    =======   ======
</Table>

     Leases covering approximately 8,616 gross (2,021 net), 10,802 gross (4,459
net) and 4,715 gross (2,133 net) undeveloped acres are scheduled to expire in
2003, 2004 and 2005, respectively. In general, our leases will continue past
their primary terms if oil and natural gas production in commercial quantities
is being produced from a well on such lease.

                                        6
<PAGE>

     The table does not include 4,305 gross (3,943 net) acres that we have a
right to acquire pursuant to various seismic option agreements at December 31,
2002. Under the terms of our option agreements, we typically have the right for
one year, subject to extensions, to exercise our option to lease the acreage at
predetermined terms.

CORE AREAS OF OPERATION

     As of December 31, 2002, 65% of our proved reserves were in south Texas and
33% in south-central Louisiana. During 2001, we added a new focus area in the
northern Rocky Mountains that could become a core area in 2003.

  TEXAS

     We currently own an interest in 27,388 net acres in south Texas. Our areas
of focus in this region are predominately in the Wilcox, Queen City, Yegua,
Vicksburg and Frio producing trends. As of December 31, 2002, we operated
approximately 61 wells, accounting for about 77% of our total net production in
Texas. We drilled 11 wells during 2002 in Texas, 10 of which were successfully
completed. The majority of our 2002 drilling activity took place at Gato Creek
and in the O'Connor Ranch East Project Area. We drilled three successful wells
at Gato Creek and performed four successful workovers of existing wells. We also
drilled three successful wells at O'Connor Ranch East where we acquired new 3-D
seismic data in 2002. During 2003, we currently expect to drill 15 to 20 wells
in our core areas in Texas. The majority of these wells are planned in our Gato
Creek, O'Connor Ranch East and Encinitas Field project areas.

  LOUISIANA

     We currently own an interest in 4,020 net acres in south-central Louisiana.
In 1997, we began to re-establish activity in Louisiana where we had been
historically active and had prior exploration success. Our operations have been
focused in the prolific gas-producing region covering parts of Acadia,
Lafayette, St. Landry and Vermilion Parishes. The exploratory focus in this area
is primarily the deep, geo-pressured gas section ranging from 12,000 to 20,000
feet in depth. We began production from our second Duson Complex discovery well,
the Thibodeaux #1, in May 2002 at a gross rate of approximately 10 MMCFPD and
475 BCPD. Edge has a 45% working interest in the well, which is operated by BTA
Oil Producers. The Thibodeaux #1 experienced increasing water production during
the second half of 2002. A workover to correct this problem was attempted in
late 2002. Due to these problems, the original completion was abandoned and a
sidetrack operation was begun in late 2002. The sidetrack was successfully
completed in 2003 and the well is currently producing at a gross rate in excess
of 10 MMCFPD and 750 BCPD. Two additional exploratory wells have reached total
depth in the first quarter 2003 and both were dry holes: the North Gueydan
prospect, a 16,500 foot Marg-Tex test in Acadia Parish and the Jericho prospect,
a Bol Mex test near the Duson Complex in Lafayette Parish. We are currently
assessing additional opportunities in South Louisiana, but have no definite
plans to drill additional wells in this area during 2003.

  NORTHERN ROCKY MOUNTAINS

     We have a 50% working interest in 67,642 gross acres (30,568 net acres) in
the northern Powder River Basin of Montana. In addition, we directed the
acquisition of 55 square miles of proprietary 3-D seismic covering a portion of
this acreage block. We have in excess of five drillable prospects identified
which we may drill in 2003 depending upon, among other things, capital
availability. This area has multiple objectives ranging from shallow coal bed
methane at 1,000 feet to a deeper Paleozoic section at approximately 11,000
feet. The objective section is generally non-pressured with lower dry hole costs
than many of our Gulf Coast plays.

MARKETING

     Our production is marketed to third parties consistent with industry
practices. Typically, oil is sold at the well-head at field-posted prices and
natural gas is sold under contract at a negotiated monthly price based upon
factors normally considered in the industry, such as distance from the well to
the transportation pipeline, well pressure, estimated reserves, quality of
natural gas and prevailing supply/demand conditions.

                                        7
<PAGE>

     Our marketing objective is to receive the highest possible wellhead price
for our product. We are aided by the presence of multiple outlets near our
production on the Gulf Coast. We take an active role in determining the
available pipeline alternatives for each property based upon historical pricing,
capacity, pressure, market relationships, seasonal variances and long-term
viability.

     There are a variety of factors which affect the market for oil and natural
gas, including the extent of domestic production and imports of oil and natural
gas, the proximity and capacity of natural gas pipelines and other
transportation facilities, demand for oil and natural gas, the marketing of
competitive fuels and the effects of state and federal regulations on oil and
natural gas production and sales. We have not experienced any difficulties in
marketing our oil and natural gas. The oil and natural gas industry also
competes with other industries in supplying the energy and fuel requirements of
industrial, commercial and individual customers.

     We market our own production where feasible with a combination of
market-sensitive pricing and forward-fixed pricing. Forward pricing is utilized
to take advantage of anomalies in the futures market and to hedge a portion of
our production at prices exceeding forecast. All such hedging transactions
provide for financial rather than physical settlement. See ITEM
7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS -- General Overview."

     Due to the instability of oil and natural gas prices, we have entered into,
from time to time, price risk management transactions (e.g., swaps, collars and
floors) for a portion of our oil and natural gas production to achieve a more
predictable cash flow, as well as to reduce exposure from price fluctuations.
While the use of these arrangements limits our ability to benefit from increases
in the price of oil and natural gas, it also reduces our potential exposure to
adverse price movements. Our hedging arrangements, to the extent we enter into
any, apply to only a portion of our production and provide only partial price
protection against declines in oil and natural gas prices and limits our
potential gains from future increases in prices. Our Board of Directors sets all
of our hedging policies, including volumes, types of instruments and counter
parties, on a quarterly basis. These policies are implemented by management
through the execution of trades by the Chief Financial Officer after
consultation and concurrence by the President and Chairman of the Board. We
account for these transactions as hedging activities and, accordingly, realized
gains and losses are included in oil and natural gas revenue during the period
the hedged transactions occur.

                                        8
<PAGE>

     Although we take some measures to attempt to control price risk, we remain
subject to price fluctuations for natural gas sold in the spot market due
primarily to seasonality of demand and other factors beyond our control.
Domestic oil prices generally follow worldwide oil prices, which are subject to
price fluctuations resulting from changes in world supply and demand. We
continue to evaluate the potential for reducing these risks by entering into
hedge transactions. Included within natural gas revenue for the years ended
December 31, 2002, 2001, and 2000 was approximately $(0.3) million, $(0.9)
million and $(1.5) million, respectively, representing net losses from hedging
activity. Included within oil revenue for the year ended December 31, 2000 was
approximately $(0.2) million representing net losses from hedging activity.

<Table>
<Caption>
                                                                               REALIZED HEDGING LOSSES
                         EFFECTIVE DATES                                   FOR THE YEAR ENDED DECEMBER 31,
                       -------------------                      MMBTU    -----------------------------------
HEDGE TYPE               BEG.      ENDING    PRICE PER MMBTU   PER DAY     2002        2001         2000
----------             --------   --------   ---------------   -------   ---------   ---------   -----------
<S>                    <C>        <C>        <C>               <C>       <C>         <C>         <C>
NATURAL GAS:
  Collar.............  02/01/00   02/29/00     $2.20-$2.31      6,000    $      --   $      --   $   (70,470)
  Collar.............  03/01/00   04/30/00     $2.20-$2.50      6,000           --          --      (135,900)
  Collar.............  05/01/00   09/30/00     $2.05-$2.63      9,000           --          --    (1,342,320)
  Collar.............  01/01/01   12/31/01     $4.50-$6.70      4,000           --    (937,120)           --
  Put Option.........  04/01/02   06/30/02     $      2.65     18,000     (163,800)         --            --
  Swap...............  09/01/02   12/31/02     $      3.59      5,000     (110,550)         --            --
  Swap...............  09/01/02   12/31/02     $      3.69      5,000      (52,600)         --            --
                                                                         ---------   ---------   -----------
    Total realized losses from gas hedging activities.................   $(326,950)  $(937,120)  $(1,548,690)
                                                                         =========   =========   ===========
</Table>

<Table>
<Caption>
                                                                              REALIZED HEDGING LOSSES
                         EFFECTIVE DATES                                  FOR THE YEAR ENDED DECEMBER 31,
                       -------------------                      MMBTU    ---------------------------------
HEDGE TYPE               BEG.      ENDING    PRICE PER MMBTU   PER DAY     2002        2001        2000
----------             --------   --------   ---------------   -------   ---------   ---------   ---------
<S>                    <C>        <C>        <C>               <C>       <C>         <C>         <C>
OIL:
Swap.................  01/01/00   03/31/00       $25.60           150    $      --   $      --   $ (49,999)
                       04/01/00   06/30/00       $22.87           125           --          --     (65,478)
                       07/01/00   09/30/00       $21.47            60           --          --     (55,635)
                       10/01/00   12/31/00       $20.46            50           --          --     (52,342)
                                                                         ---------   ---------   ---------
    Total realized losses from oil hedging activities.................   $      --   $      --   $(223,454)
                                                                         =========   =========   =========
</Table>

     In October 2002, we entered into a collar covering 10,000 MMbtus of gas per
day for all of calendar 2003. The collar structure provides us with a minimum
price for the covered gas volume of $4.00 per MMbtu and a maximum price of $4.25
per MMbtu. This structure ensured a minimum level of cash flow that gave us the
certainty to plan our drilling program for 2003 in a fashion that provided more
predictability to our activities.

     At December 31, 2002 and 2000, the fair value, or net unrealized loss, of
outstanding hedges, for the following year was approximately $(1.3) million and
$(1.1) million, respectively. No hedges were outstanding at December 31, 2001.

COMPETITION

     We encounter competition from other oil and natural gas companies in all
areas of our operations, including the acquisition of exploratory prospects and
proven properties. Our competitors include major integrated oil and natural gas
companies and numerous independent oil and natural gas companies, individuals
and drilling and income programs. Many of our competitors are large,
well-established companies with substantially larger operating staffs and
greater capital resources than ours and which, in many instances, have been
engaged in the oil and natural gas business for a much longer time than us. Such
companies may be able to pay more for exploratory prospects and productive oil
and natural gas properties and may be able to define, evaluate, bid for and
purchase a greater number of properties and prospects than our financial or
human resources permit. In addition, such companies may be able to expend
greater resources on the existing and changing technologies that we believe are
and will be increasingly important to the current and future success of oil and
natural gas companies. Our ability to explore for oil and natural gas reserves
and to acquire additional properties in the future will be dependent upon our
ability to conduct our operations, to evaluate

                                        9
<PAGE>

and select suitable properties and to consummate transactions in this highly
competitive environment. We believe that our technological expertise, our
exploration, land, drilling and production capabilities and the experience of
our management generally enable us to compete effectively. Many of our
competitors, however, have financial resources and exploration and development
budgets that are substantially greater than ours, which may adversely affect our
ability to compete with these companies.

INDUSTRY REGULATIONS

     The availability of a ready market for oil and natural gas production
depends upon numerous factors beyond our control. These factors include
regulation of oil and natural gas production, federal and state regulations
governing environmental quality and pollution control, state limits on allowable
rates of production by well or proration unit, the amount of oil and natural gas
available for sale, the availability of adequate pipeline and other
transportation and processing facilities and the marketing of competitive fuels.
For example, a productive natural gas well may be "shut-in" because of an
oversupply of natural gas or lack of an available natural gas pipeline in the
areas in which we may conduct operations. State and federal regulations
generally are intended to prevent waste of oil and natural gas, protect rights
to produce oil and natural gas between owners in a common reservoir, control the
amount of oil and natural gas produced by assigning allowable rates of
production and control contamination of the environment. Pipelines are subject
to the jurisdiction of various federal, state and local agencies. We are also
subject to changing and extensive tax laws, the effects of which cannot be
predicted. The following discussion summarizes the regulation of the United
States oil and natural gas industry. We believe that we are in substantial
compliance with the various statutes, rules, regulations and governmental orders
to which our operations may be subject, although there can be no assurance that
this is or will remain the case. Moreover, such statutes, rules, regulations and
government orders may be changed or reinterpreted from time to time in response
to economic or political conditions, and there can be no assurance that such
changes or reinterpretations will not materially adversely affect our results of
operations and financial condition. The following discussion is not intended to
constitute a complete discussion of the various statutes, rules, regulations and
governmental orders to which our operations may be subject.

     Regulation of Oil and Natural Gas Exploration and Production.  Our
operations are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for the drilling of
wells, maintaining bonding requirements in order to drill or operate wells and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells and the disposal of fluids used in connection
with operations. Our operations are also subject to various conservation laws
and regulations. These include the regulation of the size of drilling and
spacing units or proration units and the density of wells that may be drilled in
and the unitization or pooling of oil and natural gas properties. In this
regard, some states allow the forced pooling or integration of tracts to
facilitate exploration while other states rely primarily or exclusively on
voluntary pooling of lands and leases. In areas where pooling is voluntary, it
may be more difficult to form units, and therefore more difficult to develop a
project, if the operator owns less than 100% of the leasehold. In addition,
state conservation laws establish maximum rates of production from oil and
natural gas wells, generally prohibit the venting or flaring of natural gas and
impose certain requirements regarding the ratability of production. The effect
of these regulations may limit the amount of oil and natural gas we can produce
from our wells and may limit the number of wells or the locations at which we
can drill. The regulatory burden on the oil and natural gas industry increases
our costs of doing business and, consequently, affects our profitability.
Inasmuch as such laws and regulations are frequently expanded, amended and
reinterpreted, we are unable to predict the future cost or impact of complying
with such regulations.

     Regulation of Sales and Transportation of Natural Gas.  Federal legislation
and regulatory controls have historically affected the price of natural gas
produced by us, and the manner in which such production is transported and
marketed. Under the Natural Gas Act ("NGA") of 1938, the Federal Energy
Regulatory Commission (the "FERC") regulates the interstate transportation and
the sale in interstate commerce for resale of natural gas. The FERC's
jurisdiction over interstate natural gas sales and transportation was
substantially modified by the Natural Gas Policy Act of 1978 (the "NGPA"), under
which the FERC continued to regulate the maximum selling prices of certain
categories of gas sold in "first sales" in interstate and intrastate commerce.
Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the

                                        10
<PAGE>

"Decontrol Act") deregulated natural gas prices for all "first sales" of natural
gas, including all sales by us of our own production. As a result, all of our
domestically produced natural gas may now be sold at market prices, subject to
the terms of any private contracts that may be in effect. The Decontrol Act did
not affect the FERC's jurisdiction over natural gas transportation.

     Our natural gas sales are affected by intrastate and interstate gas
transportation regulation. Following the Congressional passage of the NGPA, the
FERC adopted a series of regulatory changes that have significantly altered the
transportation and marketing of natural gas. Beginning with the adoption of
"open access" regulations in Order No. 436, issued in October 1985, these
changes were intended by the FERC to foster competition by, among other things,
transforming the role of interstate pipeline companies from wholesale marketers
of gas to the primary role of gas transporters. Through similar orders affecting
intrastate pipelines that provide similar interstate services under the NGPA,
the FERC expanded the impact of these open access regulations to intrastate
commerce.

     In April 1992, the FERC issued Order No. 636 and a series of related
orders, which among other things required interstate pipelines to "unbundle"
their gas merchant services from their transportation services, thereby further
enhancing their obligation to provide open-access transportation on a not unduly
discriminatory basis for all natural gas shippers. All gas marketing by the
pipelines was required to be provided upstream at the wellhead, and, as a
result, most pipelines divested their merchant functions to a marketing
affiliate, which operates separately from the transporter and can participate in
downstream sales markets on a bundled basis, in direct competition with other
gas merchants. Order No. 636 also established a mechanism that allows shippers
to "release" their firm capacity to other shippers, either temporarily or
permanently, when it is not needed by those shippers. Although Order No. 636
does not directly regulate our production and marketing activities, it does
affect how buyers and sellers gain access to the necessary transportation
facilities and how natural gas is sold in the marketplace.

     In February 2000, the FERC issued Order No. 637 which:

     - lifted the cost-based cap on pipeline transportation rates in the
       capacity release market on an experimental basis until September 30,
       2002, for short-term releases of pipeline capacity of less than one year
       (the FERC did not renew this program),

     - permits pipelines to file for authority to charge different maximum
       cost-based rates for peak and off-peak periods,

     - encourages, but does not mandate, auctions for pipeline capacity,

     - requires pipelines to implement imbalance management services,

     - restricts the ability of pipelines to impose penalties for imbalances,
       overruns and non-compliance with operational flow orders, and

     - expands the opportunities for shippers to "segment" their capacity into
       multiple parts and implements a number of new pipeline reporting
       requirements.

     Order No. 637 also requires the FERC staff to analyze whether the FERC
should implement additional fundamental policy changes. These include whether to
pursue performance-based or other non-cost based ratemaking techniques and
whether the FERC should mandate greater standardization in terms and conditions
of service across the interstate pipeline grid. Order No. 637 was largely
affirmed by the courts and most pipelines' tariff filings to implement the
requirements of Order No. 637 have been accepted by the FERC and placed into
effect. Finally, in July 2002, the FERC commenced an inquiry into whether it
should make changes to its policy of allowing pipelines in certain circumstances
to charge "negotiated rates" for their services, including rates tied to the
natural gas commodities market indices.

     As a result of these changes, sellers and buyers of gas have gained direct
access to the particular pipeline services they need and are better able to
conduct business with a larger number of counterparties. We believe these
changes generally have improved our access to markets while, at the same time,
substantially increasing competition in the natural gas marketplace. It remains
to be seen, however, what effect the FERC's other activities will have on access
to markets, the fostering of competition and the cost of doing business. We

                                        11
<PAGE>

cannot predict what new or different regulations the FERC and other regulatory
agencies may adopt, or what effect subsequent regulations may have on our
activities.

     In the past, Congress has been very active in the area of gas regulation.
However, as discussed above, the more recent trend has been in favor of
deregulation, or "lighter handed" regulation, and the promotion of competition
in the gas industry. There regularly are other legislative proposals pending in
the Federal and state legislatures that, if enacted, would significantly affect
the petroleum industry. At the present time, it is impossible to predict what
proposals, if any, might actually be enacted by Congress or the various state
legislatures and what effect, if any, such proposals might have on us.
Similarly, and despite the trend toward federal deregulation of the natural gas
industry, whether or to what extent that trend will continue, or what the
ultimate effect will be on our sales of gas, cannot be predicted.

     We own certain natural gas pipelines that we believe meet the standards the
FERC has used to establish a pipeline's status as a gatherer not subject to FERC
jurisdiction under the NGA. State regulation of gathering facilities generally
includes various safety, environmental, and in some circumstances,
nondiscriminatory take requirements, but does not generally entail rate
regulation. Natural gas gathering may receive greater regulatory scrutiny at
both state and federal levels in the post-Order No. 636 environment.

     Oil Price Controls and Transportation Rates.  Sales of crude oil,
condensate and gas liquids by us are not currently regulated and are made at
market prices. The price we receive from the sale of these products may be
affected by the cost of transporting the products to market. Much of the
transportation is through interstate common carrier pipelines. Effective as of
January 1, 1995, the FERC implemented regulations generally grandfathering all
previously approved interstate transportation rates and establishing an indexing
system for those rates by which adjustments are made annually based on the rate
of inflation, subject to certain conditions and limitations. These regulations
have generally been approved on judicial review. Every five years, the FERC must
examine the relationship between the annual change in the applicable index and
the actual cost changes experienced in the oil pipeline industry. The first such
review was completed in 2000, and on December 14, 2000, FERC reaffirmed the
current index. The FERC's regulation of oil transportation rates may tend to
increase the cost of transporting oil and natural gas liquids by interstate
pipeline, although the annual adjustments may result in decreased rates in a
given year. Following a successful court challenge of these orders by an
association of oil pipelines on February 24, 2003, the FERC acting on remand
increased the index slightly for the current five-year period, effective July
2001. We are not able at this time to predict the effects of these regulations,
if any, on the transportation costs associated with oil production from our oil
producing operations.

     Environmental Regulations.  Our operations are subject to numerous federal,
state and local laws and regulations governing the discharge of materials into
the environment or otherwise relating to environmental protection. These laws
and regulations may require the acquisition of a permit before drilling
commences, restrict the types, quantities and concentration of various
substances that can be released into the environment in connection with drilling
and production activities, limit or prohibit drilling activities on certain
lands within wilderness, wetlands and other protected areas, require remedial
measures to mitigate pollution from former operations, such as pit closure and
plugging abandoned wells, and impose substantial liabilities for pollution
resulting from production and drilling operations. Public interest in the
protection of the environment has increased dramatically in recent years. The
trend of more expansive and stricter environmental legislation and regulations
applied to the oil and natural gas industry could continue, resulting in
increased costs of doing business and consequently affecting profitability. To
the extent laws are enacted or other governmental action is taken that restricts
drilling or imposes more stringent and costly waste handling, disposal and
cleanup requirements, our business and prospects could be adversely affected.

     We generate wastes that may be subject to the federal Resource Conservation
and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental
Protection Agency ("EPA") and various state agencies have limited the approved
methods of disposal for certain hazardous and nonhazardous wastes. Furthermore,
certain wastes generated by our oil and natural gas operations that are
currently exempt from treatment as "hazardous wastes" may in the future be
designated as "hazardous wastes," and therefore be subject to more rigorous and
costly operating and disposal requirements.

     We currently own or lease numerous properties that for many years have been
used for the exploration and production of oil and natural gas. Although we
believe that we have used good operating and waste
                                        12
<PAGE>

disposal practices, prior owners and operators of these properties may not have
used similar practices, and hydrocarbons or other wastes may have been disposed
of or released on or under the properties owned or leased by us or on or under
locations where such wastes have been taken for disposal. In addition, many of
these properties have been operated by third parties whose treatment and
disposal or release of hydrocarbons or other wastes was not under our control.
These properties and the wastes disposed thereon may be subject to the
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"),
RCRA and analogous state laws as well as state laws governing the management of
oil and natural gas wastes. Under such laws, we could be required to remove or
remediate previously disposed wastes (including wastes disposed of or released
by prior owners or operators) or property contamination (including groundwater
contamination) or to perform remedial plugging operations to prevent future
contamination.

     Our operations may be subject to the Clean Air Act ("CAA") and comparable
state and local requirements. Amendments to the CAA were adopted in 1990 and
contain provisions that have resulted in the gradual imposition of certain
pollution control requirements with respect to air emissions from our
operations. The EPA and states developed and continue to develop regulations to
implement these requirements. We may be required to incur certain capital
expenditures in the next several years for air pollution control equipment in
connection with maintaining or obtaining operating permits and approvals
addressing other air emission-related issues. However, we do not believe our
operations will be materially adversely affected by any such requirements.

     Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as Edge, to prepare and implement spill
prevention, control, countermeasure ("SPCC") and response plans relating to the
possible discharge of oil into surface waters. SPCC plans at certain of our
properties were developed and implemented in 1999. The Oil Pollution Act of 1990
("OPA") contains numerous requirements relating to the prevention of and
response to oil spills into waters of the United States. The OPA subjects owners
of facilities to strict joint and several liability for all containment and
cleanup costs and certain other damages arising from a spill, including, but not
limited to, the costs of responding to a release of oil to surface waters. The
OPA also requires owners and operators of offshore facilities that could be the
source of an oil spill into federal or state waters, including wetlands, to post
a bond, letter of credit or other form of financial assurance in amounts ranging
from $10 million in specified state waters to $35 million in federal outer
continental shelf waters to cover costs that could be incurred by governmental
authorities in responding to an oil spill. Such financial assurances may be
increased by as much as $150 million if a formal risk assessment indicates that
the increase is warranted. Noncompliance with OPA may result in varying civil
and criminal penalties and liabilities. Our operations are also subject to the
federal Clean Water Act ("CWA") and analogous state laws. In accordance with the
CWA, the state of Louisiana has issued regulations prohibiting discharges of
produced water in state coastal waters effective July 1, 1997. Pursuant to other
requirements of the CWA, the EPA has adopted regulations concerning discharges
of storm water runoff. This program requires covered facilities to obtain
individual permits, participate in a group permit or seek coverage under an EPA
general permit. While certain of our properties may require permits for
discharges of storm water runoff, we believe that we will be able to obtain, or
be included under, such permits, where necessary, and make minor modifications
to existing facilities and operations that would not have a material effect on
us. Like OPA, the CWA and analogous state laws relating to the control of water
pollution provide varying civil and criminal penalties and liabilities for
releases of petroleum or its derivatives into surface waters or into the ground.

     CERCLA, also known as the "Superfund" law, and similar state laws impose
liability, without regard to fault or the legality of the original conduct, on
certain 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 the disposal site or sites where the release occurred
and companies that disposed or arranged for the disposal of the hazardous
substances found at the site. Persons who are or were responsible for releases
of hazardous substances under CERCLA may be subject to joint and several
liability for the costs of cleaning up the hazardous substances that have been
released into the environment, for damages to natural resources and for the
costs of certain health studies, 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.

                                        13
<PAGE>

     We also are subject to a variety of federal, state and local permitting and
registration requirements relating to protection of the environment. Management
believes that we are in substantial compliance with current applicable
environmental laws and regulations and that continued compliance with existing
requirements would not have a material adverse effect on us.

OPERATING HAZARDS AND INSURANCE

     The oil and natural gas business involves a variety of operating risks,
including the risk of fire, explosion, blow-out, pipe failure, casing collapse,
abnormally pressured formations and environmental hazards such as oil spills,
natural gas leaks, ruptures and discharges of toxic gases, the occurrence of any
of which could result in substantial losses to us due to injury or loss of life,
severe damage to or destruction of property, natural resources and equipment,
pollution or other environmental damage, cleanup responsibilities, regulatory
investigation and penalties and suspension of operations.

     In accordance with customary industry practice, we maintain insurance
against some, but not all, of the risks described above. Our insurance does not
cover business interruption or protect against loss of revenue. There can be no
assurance that any insurance obtained by us will be adequate to cover any losses
or liabilities. We cannot predict the continued availability of insurance or the
availability of insurance at premium levels that justify its purchase. The
occurrence of a significant event not fully insured or indemnified against could
materially and adversely affect our financial condition and operations.

TITLE TO PROPERTIES

     Except as discussed under "ITEM 3. LEGAL PROCEEDINGS" below, we believe we
have satisfactory title to all of our producing properties in accordance with
standards generally accepted in the oil and natural gas industry. Our properties
are subject to customary royalty interests, liens incident to operating
agreements, liens for current taxes and other burdens, which we believe, do not
materially interfere with the use of or affect the value of such properties. As
is customary in the industry in the case of undeveloped properties, little
investigation of record title is made at the time of acquisition (other than a
preliminary review of local records). Investigations, including a title opinion
of local counsel, are made before commencement of drilling operations.

EMPLOYEES

     At December 31, 2002, we had 33 full-time employees. We believe that our
relationships with our employees are good. None of our employees are covered by
a collective bargaining agreement. From time to time, we utilize the services of
independent consultants and contractors to perform various professional
services, particularly in the areas of construction, design, well site
surveillance, permitting and environmental assessment. Field and on-site
production operation services, such as pumping, maintenance, dispatching,
inspection and testing are generally provided by independent contractors.

OFFICE AND EQUIPMENT

     Late in 2002, we negotiated a lease for new offices beginning in February
2003 at 1301 Travis Street, Suite 2000, Houston, Texas. The move into our new
space, covering 20,500 square feet (compared to 28,200 square feet under our
previous lease), took place during the first week of February 2003. We believe
that the combination of lower rental rates and smaller space will significantly
reduce our future general and administrative costs. See Note 6 to our
consolidated financial statements.

FORWARD LOOKING INFORMATION AND RISK FACTORS

     Certain of the statements contained in all parts of this document
(including the portion, if any, to which this Form 10-K is attached), including,
but not limited to, those relating to our drilling plans (including scheduled
and budgeted wells), the effect of changes in strategy and business discipline,
future tax matters, our 3-D project portfolio, future general and administrative
expenses on a per unit of production basis, changes in wells operated and
reserves, future growth and expansion, future exploration, future seismic data
(including timing and results), expansion of operation, our ability to generate
additional prospects, review of outside generated prospects and acquisitions,
additional reserves and reserve increases, enhancement of visualization
                                        14
<PAGE>

and interpretation strengths, expansion and improvement of capabilities,
integration of new technology into operations, credit facilities, attraction of
new members to the exploration team, future compensation programs, new focus on
core areas, new prospects and drilling locations, future capital expenditures
(or funding thereof) and working capital, sufficiency of future working capital,
borrowings and capital resources and liquidity, projected cash flows from
operations, expectation or timing of reaching payout, outcome, effects or timing
of any legal proceedings or contingencies, the number, timing or results of any
wells, the plans for timing, interpretation and results of new or existing
seismic surveys or seismic data, future production or reserves, future
acquisition of leases, lease options or other land rights and any other
statements regarding future operations, financial results, opportunities,
growth, business plans and strategy and other statements that are not historical
facts are forward looking statements. These forward-looking statements reflect
our current view of future events and financial performance. When used in this
document, the words "budgeted," "anticipate," "estimate," "expect," "may,"
"project," "believe," "intend," "plan," "potential" and similar expressions are
intended to be among the statements that identify forward looking statements.
These forward-looking statements speak only as of their dates and should not be
unduly relied upon. We undertake no obligation to publicly update or revise any
forward-looking statement, whether as a result of new information, future
events, or otherwise. Such statements involve risks and uncertainties,
including, but not limited to, those set forth below and other factors detailed
in this document and our other filings with the Commission. Should one or more
of these risks or uncertainties materialize, or should underlying assumptions
prove incorrect, actual outcomes may vary materially from those indicated.

  OIL AND GAS DRILLING IS A SPECULATIVE ACTIVITY AND INVOLVES NUMEROUS RISKS AND
  SUBSTANTIAL AND UNCERTAIN COSTS WHICH COULD ADVERSELY AFFECT US.

     Our growth will be materially dependent upon the success of our future
drilling program. Drilling for oil and gas involves numerous risks, including
the risk that no commercially productive oil or natural gas reservoirs will be
encountered. The cost of drilling, completing and operating wells is substantial
and uncertain, and drilling operations may be curtailed, delayed or cancelled as
a result of a variety of factors beyond our control, including unexpected
drilling conditions, pressure or irregularities in formations, equipment
failures or accidents, adverse weather conditions, compliance with governmental
requirements and shortages or delays in the availability of drilling rigs or
crews and the delivery of equipment. Our future drilling activities may not be
successful and, if unsuccessful, such failure will have an adverse effect on our
future results of operations and financial condition. Our overall drilling
success rate or our drilling success rate for activity within a particular
geographic area may decline. We may ultimately not be able to lease or drill
identified or budgeted prospects within our expected time frame, or at all. We
may not be able to lease or drill a particular prospect because, in some cases,
we identify a prospect or drilling location before seeking an option or lease
rights in the prospect or location. Similarly, our drilling schedule may vary
from our capital budget. The final determination with respect to the drilling of
any scheduled or budgeted wells will be dependent on a number of factors,
including (i) the results of exploration efforts and the acquisition, review and
analysis of the seismic data, (ii) the availability of sufficient capital
resources to us and the other participants for the drilling of the prospects,
(iii) the approval of the prospects by other participants after additional data
has been compiled, (iv) economic and industry conditions at the time of
drilling, including prevailing and anticipated prices for oil and natural gas
and the availability of drilling rigs and crews, (v) our financial resources and
results and (vi) the availability of leases and permits on reasonable terms for
the prospects. These projects may not be successfully developed and the wells,
if drilled, may not encounter reservoirs of commercially productive oil or
natural gas. See ITEM 7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS -- General Overview" and ITEMS 1 AND
2. -- "BUSINESS AND PROPERTIES -- CORE AREAS OF OPERATION."

  OIL AND NATURAL GAS PRICES ARE HIGHLY VOLATILE IN GENERAL AND LOW PRICES
  NEGATIVELY AFFECT OUR FINANCIAL RESULTS.

     Our revenue, profitability, cash flow, future growth and ability to borrow
funds or obtain additional capital, as well as the carrying value of our
properties, are substantially dependent upon prevailing prices of oil and
natural gas. Our reserves are predominantly natural gas; therefore changes in
natural gas prices may have a particularly large impact on our financial
results. Lower oil and natural gas prices also may reduce the amount of oil and
natural gas that we can produce economically. Historically, the markets for oil
and natural
                                        15
<PAGE>

gas have been volatile, and such markets are likely to continue to be volatile
in the future. Prices for oil and natural gas are subject to wide fluctuation in
response to relatively minor changes in the supply of and demand for oil and
natural gas, market uncertainty and a variety of additional factors that are
beyond our control. These factors include the level of consumer product demand,
weather conditions, domestic and foreign governmental regulations, the price and
availability of alternative fuels, political conditions, the foreign supply of
oil and natural gas, the price of foreign imports and overall economic
conditions. Declines in oil and natural gas prices may materially adversely
affect our financial condition, liquidity, and ability to finance planned
capital expenditures and results of operations. See ITEM 7. -- "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS -- General Overview" and ITEMS 1 AND 2. -- "BUSINESS AND
PROPERTIES -- OIL AND NATURAL GAS RESERVES" AND "-- MARKETING."

     We have in the past and may in the future be required to write down the
carrying value of our oil and natural gas properties when oil and natural gas
prices are depressed or unusually volatile. Whether we will be required to take
such a charge will depend on the prices for oil and natural gas at the end of
any quarter and the effect of reserve additions or revisions and capital
expenditures during such quarter. If a write down is required, it would result
in a charge to earnings and would not impact cash flow from operating
activities.

  WE HAVE HEDGED AND MAY CONTINUE TO HEDGE A PORTION OF OUR PRODUCTION, WHICH
  MAY RESULT IN OUR MAKING CASH PAYMENTS OR PREVENT US FROM RECEIVING THE FULL
  BENEFIT OF INCREASES IN PRICES FOR OIL AND GAS.

     In order to reduce our exposure to short-term fluctuations in the price of
oil and natural gas, we periodically enter into hedging arrangements. Our
hedging arrangements apply to only a portion of our production and provide only
partial price protection against declines in oil and natural gas prices. Such
hedging arrangements may expose us to risk of financial loss in certain
circumstances, including instances where production is less than expected, our
customers fail to purchase contracted quantities of oil or natural gas or a
sudden, unexpected event materially impacts oil or natural gas prices. In
addition, our hedging arrangements may limit the benefit to us of increases in
the price of oil and natural gas. See ITEM 7. -- "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- General Overview"
and ITEMS 1 AND 2. -- "BUSINESS AND PROPERTIES -- MARKETING."

  WE DEPEND ON SUCCESSFUL EXPLORATION, DEVELOPMENT AND ACQUISITIONS TO MAINTAIN
  RESERVES AND REVENUE IN THE FUTURE.

     In general, the volume of production from oil and natural gas properties
declines as reserves are depleted, with the rate of decline depending on
reservoir characteristics. Except to the extent we acquire properties containing
proved reserves or conduct successful exploration and development activities, or
both, our proved reserves will decline. Our future oil and natural gas
production is, therefore, highly dependent upon our level of success in finding
or acquiring additional reserves. In addition, we are dependent on finding
partners for our exploratory activity. To the extent that others in the industry
do not have the financial resources or choose not to participate in our
exploration activities, we will be adversely affected.

  WE ARE SUBJECT TO SUBSTANTIAL OPERATING RISKS WHICH MAY ADVERSELY AFFECT THE
  RESULTS OF OUR OPERATIONS.

     The oil and natural gas business involves certain operating hazards such as
well blowouts, mechanical failures, explosions, uncontrollable flows of oil,
natural gas or well fluids, fires, formations with abnormal pressures,
pollution, releases of toxic gas and other environmental hazards and risks. We
could suffer substantial losses as a result of any of these events. We are not
fully insured against all risks incident to our business.

     We are not the operator of some of our wells. As a result, our operating
risks for those wells and our ability to influence the operations for these
wells are less subject to our control. Operators of these wells may act in ways
that are not in our best interests. See ITEMS 1 AND 2. -- "BUSINESS AND
PROPERTIES -- OPERATING HAZARDS AND INSURANCE."

                                        16
<PAGE>

  THE LOSS OF KEY PERSONNEL COULD ADVERSELY AFFECT US.

     We depend to a large extent on the services of certain key management
personnel, including our executive officers and other key employees, the loss of
any of which could have a material adverse effect on our operations. We do not
maintain key-man life insurance with respect to any of our employees. We believe
that our success is also dependent upon our ability to continue to employ and
retain skilled technical personnel. See ITEMS 1 AND 2. -- "BUSINESS AND
PROPERTIES -- Technology."

  OUR OPERATIONS HAVE SIGNIFICANT CAPITAL REQUIREMENTS WHICH, IF NOT MET, WILL
  HINDER OPERATIONS.

     We have experienced and expect to continue to experience substantial
working capital needs due to our active exploration, development and acquisition
programs. Additional financing may be required in the future to fund our growth.
We may not be able to obtain such additional financing and financing under
existing or new credit facilities may not be available in the future. In the
event such capital resources are not available to us, our drilling and other
activities may be curtailed. See ITEM 7. -- "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- Liquidity and
Capital Resources."

  GOVERNMENT REGULATION AND LIABILITY FOR ENVIRONMENTAL MATTERS MAY ADVERSELY
  AFFECT OUR BUSINESS AND RESULTS OF OPERATIONS.

     Oil and natural gas operations are subject to various federal, state and
local government regulations, which may be changed from time to time. Matters
subject to regulation include discharge permits for drilling operations,
drilling bonds, reports concerning operations, the spacing of wells, unitization
and pooling of properties and taxation. From time to time, regulatory agencies
have imposed price controls and limitations on production by restricting the
rate of flow of oil and natural gas wells below actual production capacity in
order to conserve supplies of oil and natural gas. There are federal, state and
local laws and regulations primarily relating to protection of human health and
the environment applicable to the development, production, handling, storage,
transportation and disposal of oil and natural gas, by-products thereof and
other substances and materials produced or used in connection with oil and
natural gas operations. In addition, we may be liable for environmental damages
caused by previous owners of property we purchase or lease. As a result, we may
incur substantial liabilities to third parties or governmental entities. We are
also subject to changing and extensive tax laws, the effects of which cannot be
predicted. The implementation of new, or the modification of existing, laws or
regulations could have a material adverse effect on us. See ITEMS 1 AND 2. --
"BUSINESS AND PROPERTIES -- INDUSTRY REGULATIONS."

  WE MAY HAVE DIFFICULTY MANAGING ANY FUTURE GROWTH AND THE RELATED DEMANDS ON
  OUR RESOURCES AND MAY HAVE DIFFICULTY IN ACHIEVING FUTURE GROWTH.

     We have experienced growth in the past through the expansion of our
drilling program and, more recently, acquisitions. This expansion was curtailed
in 1998 and 1999, but resumed in 2000 and increased in 2001 and 2002. Further
expansion is anticipated in 2003 both through drilling efforts and possible
acquisitions. Any future growth may place a significant strain on our financial,
technical, operational and administrative resources. Our ability to grow will
depend upon a number of factors, including our ability to identify and acquire
new exploratory prospects, our ability to develop existing prospects, our
ability to continue to retain and attract skilled personnel, the results of our
drilling program and acquisition efforts, hydrocarbon prices and access to
capital. We may not be successful in achieving or managing growth and any such
failure could have a material adverse effect on us.

  WE FACE STRONG COMPETITION FROM LARGER OIL AND NATURAL GAS COMPANIES.

     Our competitors include major integrated oil and natural gas companies and
numerous independent oil and natural gas companies, individuals and drilling and
income programs. Many of our competitors are large, well-established companies
with substantially larger operating staffs and greater capital resources than
us. We may not be able to successfully conduct our operations, evaluate and
select suitable properties and consummate transactions in this highly
competitive environment. Specifically, these larger competitors may be able to
pay more for exploratory prospects and productive oil and natural gas properties
and may be able to

                                        17
<PAGE>

define, evaluate, bid for and purchase a greater number of properties and
prospects than our financial or human resources permit. In addition, such
companies may be able to expend greater resources on the existing and changing
technologies that we believe are and will be increasingly important to attaining
success in the industry. See ITEMS 1 AND 2. -- "BUSINESS AND
PROPERTIES -- COMPETITION."

  THE OIL AND NATURAL GAS RESERVE DATA INCLUDED IN OR INCORPORATED BY REFERENCE
  IN THIS DOCUMENT ARE ESTIMATES BASED ON ASSUMPTIONS THAT MAY BE INACCURATE AND
  EXISTING ECONOMIC AND OPERATING CONDITIONS THAT MAY DIFFER FROM FUTURE
  ECONOMIC AND OPERATING CONDITIONS.

     Reservoir engineering is a subjective and inexact process of estimating
underground accumulations of oil and natural gas that cannot be measured in an
exact manner and is based upon assumptions that may vary considerably from
actual results. Accordingly, reserve estimates may be subject to downward or
upward adjustment. Actual production, revenue and expenditures with respect to
our reserves will likely vary from estimates, and such variances may be
material. The information regarding discounted future net cash flows included in
this report should not be considered as the current market value of the
estimated oil and natural gas reserves attributable to our properties. As
required by the Commission, the estimated discounted future net cash flows from
proved reserves are based on prices and costs as of the date of the estimate,
while actual future prices and costs may be materially higher or lower. Actual
future net cash flows also will be affected by factors such as the amount and
timing of actual production, supply and demand for oil and natural gas,
increases or decreases in consumption, and changes in governmental regulations
or taxation. In addition, the 10% discount factor, which is required by
Financial Accounting Standards Board in Statement of Financial Accounting
Standards No. 69, "Disclosures About Oil and Natural Gas Producing Activities"
to be used in calculating discounted future net cash flows for reporting
purposes, is not necessarily the most appropriate discount factor based on
interest rates in effect from time to time and risks associated with us or the
oil and natural gas industry in general. See ITEMS 1 AND 2. -- "BUSINESS AND
PROPERTIES -- Oil and Natural Gas Reserves."

  OUR CREDIT FACILITY HAS SUBSTANTIAL OPERATING RESTRICTIONS AND FINANCIAL
  COVENANTS AND WE MAY HAVE DIFFICULTY OBTAINING ADDITIONAL CREDIT WHICH COULD
  ADVERSELY AFFECT OPERATIONS.

     Over the past few years, increases in commodity prices, in proved reserve
amounts and the resultant increase in estimated discounted future net revenue,
has allowed us to increase our available borrowing amounts. In the future,
commodity prices may decline, we may increase our borrowings or our borrowing
base may be adjusted downward. Our credit facility is secured by a pledge of
substantially all of our assets and has covenants that limit additional
borrowings, sales of assets and the distributions of cash or properties and that
prohibit the payment of dividends and the incurrence of liens. The revolving
credit facility also requires that specified financial ratios be maintained. The
restrictions of our credit facility and the difficulty in obtaining additional
debt financing may have adverse consequences on our operations and financial
results, including our ability to obtain financing for working capital, capital
expenditures, our drilling program, purchases of new technology or other
purposes may be impaired or such financing may be on terms unfavorable to us; we
may be required to use a substantial portion of our cash flow to make debt
service payments, which will reduce the funds that would otherwise be available
for operations and future business opportunities; a substantial decrease in our
operating cash flow or an increase in our expenses could make it difficult for
us to meet debt service requirements and require us to modify operations; and we
may become more vulnerable to downturns in our business or the economy
generally.

     Our ability to obtain and service indebtedness will depend on our future
performance, including our ability to manage cash flow and working capital,
which are in turn subject to a variety of factors beyond our control. Our
business may not generate cash flow at or above anticipated levels or we may not
be able to borrow funds in amounts sufficient to enable us to service
indebtedness, make anticipated capital expenditures or finance our drilling
program. If we are unable to generate sufficient cash flow from operations or to
borrow sufficient funds in the future to service our debt, we may be required to
curtail portions of our drilling program, sell assets, reduce capital
expenditures, refinance all or a portion of our existing debt or obtain
additional financing. We may not be able to refinance our debt or obtain
additional financing, particularly in view of current industry conditions, the
restrictions on our ability to incur debt under our existing debt arrangements,
and the fact that substantially all of our assets are currently pledged to
secure obligations under our bank

                                        18
<PAGE>

credit facility. See Item 7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- Liquidity and Capital
Resources" and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS -- Credit Facility."

  OUR ACQUISITION PROGRAM MAY BE UNSUCCESSFUL, PARTICULARLY IN LIGHT OF OUR
  LIMITED ACQUISITION EXPERIENCE.

     Because we have not typically purchased properties, we may not be in as
good a position as our more experienced competitors to execute a successful
acquisition program. The successful acquisition of producing properties requires
an assessment of recoverable reserves, future oil and natural gas prices,
operating costs, potential environmental and other liabilities and other
factors. Such assessments, even when performed by experienced personnel, are
necessarily inexact and their accuracy inherently uncertain. Our review of
subject properties will not reveal all existing or potential problems,
deficiencies and capabilities. We may not always perform inspections on every
well, and may not be able to observe structural and environmental problems even
when we undertake an inspection. Even when problems are identified, the seller
may be unwilling or unable to provide effective contractual protection against
all or part of such problems. Any acquisition of property interests by us may
not be successful and, if unsuccessful, such failure may have an adverse effect
on our future results of operations and financial condition.

  WE DO NOT INTEND TO PAY DIVIDENDS AND OUR ABILITY TO PAY DIVIDENDS IS
  RESTRICTED.

     We currently intend to retain any earnings for the future operation and
development of our business and do not currently anticipate paying any dividends
in the foreseeable future. Any future dividends also may be restricted by our
then-existing loan agreements. See ITEM 7. -- "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- Liquidity and
Capital Resources" and Note 4 to our consolidated financial statements.

  OUR RELIANCE ON THIRD PARTIES FOR GATHERING AND DISTRIBUTING COULD CURTAIL
  FUTURE EXPLORATION AND PRODUCTION ACTIVITIES.

     The marketability of our production depends upon the proximity of our
reserves to, and the capacity of, facilities and third party services, including
oil and natural gas gathering systems, pipelines, trucking or terminal
facilities, and processing facilities. The unavailability or lack of capacity of
such services and facilities could result in the shut-in of producing wells or
the delay or discontinuance of development plans for properties. A shut-in or
delay or discontinuance could adversely affect our financial condition. In
addition, federal and state regulation of oil and natural gas production and
transportation affect our ability to produce and market our oil and natural gas
on a profitable basis.

  PROVISIONS OF DELAWARE LAW AND OUR CHARTER AND BYLAWS MAY DELAY OR PREVENT
  TRANSACTIONS THAT WOULD BENEFIT STOCKHOLDERS.

     Our Certificate of Incorporation and Bylaws and the Delaware General
Corporation Law contain provisions that may have the effect of delaying,
deferring or preventing a change of control of the company. These provisions,
among other things, provide for a classified Board of Directors with staggered
terms, restrict the ability of stockholders to take action by written consent,
authorize the Board of Directors to set the terms of Preferred Stock, and
restrict our ability to engage in transactions with 15% stockholders.

     Because of these provisions, persons considering unsolicited tender offers
or other unilateral takeover proposals may be more likely to negotiate with our
board of directors rather than pursue non-negotiated takeover attempts. As a
result, these provisions may make it more difficult for our stockholders to
benefit from transactions that are opposed by an incumbent board of directors.

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<PAGE>

CERTAIN DEFINITIONS

     The definitions set forth below shall apply to the indicated terms as used
in this Form 10-K. All volumes of natural gas referred to herein are stated at
the legal pressure base of the state or area where the reserves exist and at 60
degrees Fahrenheit and in most instances are rounded to the nearest major
multiple.

     After payout.  With respect to an oil or natural gas interest in a
property, refers to the time period after which the costs to drill and equip a
well have been recovered.

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

     Bbls/d.  Stock tank barrels per day.

     Bcf.  Billion cubic feet.

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

     Before payout.  With respect to an oil and natural gas interest in a
property, refers to the time period before which the costs to drill and equip a
well have been recovered.

     Completion.  The installation of permanent equipment for the production of
oil or natural gas or, in the case of a dry hole, the reporting of abandonment
to the appropriate agency.

     Developed acreage.  The number of acres which are allocated or assignable
to producing wells or wells capable of production.

     Development well.  A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.

     Dry hole or well.  A well found to be incapable of producing hydrocarbons
in sufficient quantities such that proceeds from the sale of such production
exceed oil and natural gas operating expenses and taxes.

     Exploratory well.  A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.

     Farm-in or farm-out.  An agreement whereunder the owner of a working
interest in an oil and natural gas lease assigns the working interest or a
portion thereof to another party who desires to drill on the leased acreage.
Generally, the assignee is required to drill one or more wells in order to earn
its interest in the acreage. The assignor usually retains a royalty and/or
reversionary interest in the lease. The interest received by an assignee is a
"farm-in" while the interest transferred by the assignor is a "farm-out."

     Field.  An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.

     Finding costs.  Costs associated with acquiring and developing proved oil
and natural gas reserves which are capitalized by us pursuant to generally
accepted accounting principles, including all costs involved in acquiring
acreage, geological and geophysical work and the cost of drilling and completing
wells, excluding those costs attributable to unproved undeveloped property.

     Gross acres or gross wells.  The total acres or wells, as the case may be,
in which a working interest is owned.

     MBbls.  One thousand barrels of crude oil or other liquid hydrocarbons.

     Mcf.  One thousand cubic feet.

     Mcf/d.  One thousand cubic feet per day.

     Mcfe.  One thousand cubic feet equivalent determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids,
which approximates the relative energy content of crude oil, condensate and
natural gas liquids as compared to natural gas. Prices have historically been
higher or substantially higher for crude oil than natural gas on an energy
equivalent basis although there have been
                                        20
<PAGE>

periods in which they have been lower or substantially lower.

     MMcf.  One million cubic feet.

     MMcfe.  One million cubic feet equivalent determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids,
which approximates the relative energy content of crude oil, condensate and
natural gas liquids as compared to natural gas.

     Net acres or net wells.  The sum of the fractional working interests owned
in gross acres or gross wells.

     NGL's.  Natural gas liquids measured in barrels.

     NRI or Net Revenue Interests.  The share of production after satisfaction
of all royalty, overriding royalty, oil payments and other nonoperating
interests.

     Normally pressured reservoirs.  Reservoirs with a formation-fluid pressure
equivalent to 0.465 PSI per foot of depth from the surface. For example, if the
formation pressure is 4,650 PSI at 10,000 feet, then the pressure is considered
to be normal.

     Over-pressured reservoirs.  Reservoirs subject to abnormally high pressure
as a result of certain types of subsurface formations.

     Petrophysical study.  Study of rock and fluid properties based on well log
and core analysis.

     Plant Products.  Liquids generated by a plant facility and include propane,
iso-butane, normal butane, pentane and ethane.

     Present value.  When used with respect to oil and natural gas reserves, the
estimated future gross revenue to be generated from the production of proved
reserves, net of estimated production and future development costs, using prices
and costs in effect as of the date indicated, without giving effect to
nonproperty-related expenses such as general and administrative expenses, debt
service and future income tax expense or to depletion, depreciation, and
amortization, discounted using an annual discount rate of 10%.

     Productive well.  A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceeds production expenses and taxes.

     Proved developed nonproducing reserves.  Proved developed reserves expected
to be recovered from zones behind casing in existing wells.

     Proved developed producing reserves.  Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and able to produce to market.

     Proved developed reserves.  Proved reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.

     Proved reserves.  The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.

     Proved undeveloped location.  A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.

     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.

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

     Reservoir.  A porous and permeable underground formation containing a
natural accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.

     Royalty interest.  An interest in an oil and natural gas property entitling
the owner to a share of oil or natural gas production free of costs of
production.

                                        21
<PAGE>

     3-D seismic.  Advanced technology method of detecting accumulations of
hydrocarbons identified through a three-dimensional picture of the subsurface
created by the collection and measurement of the intensity and timing of sound
waves transmitted into the earth as they reflect back to the surface.

     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 natural gas regardless of whether such acreage contains proved
reserves.

     Working interest or WI.  The operating interest that gives the owner the
right to drill, produce and conduct operating activities on the property and a
share of production.

     Workover.  Operations on a producing well to restore or increase
production.

ITEM 3.  LEGAL PROCEEDINGS

     From time to time we are a party to various legal proceedings arising in
the ordinary course of business. While the outcome of lawsuits cannot be
predicted with certainty, we are not currently a party to any proceeding that we
believe, if determined in a manner adverse to us, could have a potential
material adverse effect on our financial condition, results of operations or
cash flows.

     In October 2001, the Company was sued by certain mineral owners in its Mew
lease, upon which the Company and its partners drilled and completed the Mew No.
1 well in the Brandon Area, Duval County, Texas. The suit named the Company,
Santos USA and Mark Smith, an independent landman, as Defendants, and is filed
in the 229th Judicial District Court of Duval County, Texas. The suit sought a
declaratory judgment to set aside certain quitclaim deeds between the Mew
lessors that were intended to result in a partition of the mineral estate
between the various members of the Mew family in the land where the well is
located and other lands. The pleadings alleged failure of consideration, fraud,
failure to consummate the partition, bad faith trespass and conversion. As part
of the leasing effort for the prospect, some members of the Mew family had
sought to partition their minerals under the tracts where they owned the surface
in full. The Mew heirs, from whom the Company acquired leases, stood to lose a
portion of their mineral interest if the quitclaim deeds are set aside. Were
this to happen, it could have the effect of voiding the Company's leases as to
an undivided one-third of the unit acreage for the Mew well and the Mew lease.
Plaintiffs sought unspecified actual and exemplary damages against the Company
and Santos arising out of the alleged fraud committed by the Company and Mark
Smith. They also sought damages from Santos for the value of the oil and natural
gas produced and saved from the Mew well, or alternatively, for the value of the
oil and natural gas produced less the cost of drilling, completing and operating
the well. The Company has a 12.5% working interest in the well. To date, the Mew
well has produced $5.7 million in net revenue and has cost $3.6 million to
drill, complete and operate. Estimated gross proved reserves are 111.6 MBbls and
4.6 Bcf. In October 2002, the Company reached a mediated settlement with all
parties to the litigation whereby Edge would make a one-time payment of $264,000
to the Mews, and in return, the Mews released all claims except a potential
drainage claim involving an offsetting section, and agreed to grant a new oil
and gas lease covering the disputed mineral interest in the Mew well site tract.
In addition, all claims as between the working interest owners were released.
The settlement has been consummated and an order of dismal has been obtained
from the Court.

     In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in the N. LaCopita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil filed a
counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. ExxonMobil sought
unspecified damages for the lost profits on the sale of the hydrocarbons from
this property, and for a determination of whether the Company and the other
working interest owners were in good faith or bad faith in trespassing on this
lease. If a determination of bad faith were made, the parties would not be able
                                        22
<PAGE>

to recover their costs of developing this property from the revenues therefrom.
While there is always a risk in the outcome of the litigation, the Company
believes there is no question that it acted in good faith and vigorously
defended its position. In February 2003, the Company, GMT and the other working
interest parties entered into a compromise and settlement agreement with Exxon
and Mrs. Neblett. Pursuant to the settlement, the Neblett wells have been
assigned to Exxon along with all operating responsibility, and all working
interest parties, including the Company, have been made whole for all out of
pocket costs incurred in drilling, completing, equipping and operating the
Neblett wells, including lease costs and royalty payments. The Company's share
of such reimbursed costs was $27,198. In addition, Mrs. Neblett will repay the
amount of the lease bonus and all royalty overpayments she received from GMT and
the other working interest parties, including the Company. Such payment is
secured by her future royalty interest payments in the wells, and other security
described in the settlement agreement, and is due in full on or before December
1, 2003. The Company's share of such lease bonus and royalty reimbursements is
$74,040. The parties have agreed to a dismissal of all claims in this case, and
a motion to dismiss with prejudice has been filed with the court.

     In a separate but related matter, certain nonparticipating royalty owners
represented by attorney John Mann in Laredo, have made demands on GMT as
operator, to pay certain royalty payments previously paid to Mrs. Neblett on
production from these wells, plus future royalty payments on such production. As
part of the settlement agreement, monies that were otherwise payable to Mrs.
Neblett attributable to her valid royalty interest under the ExxonMobil lease,
subject to execution of valid division orders and approval of their title, will
be paid to the Mann clients on account of their nonparticipating royalty
interest. There are other nonparticipating royalty owners similarly situated to
the Mann clients that have not made demands on GMT or the Company, whose claims,
if any, will be dealt with if and when they are made. There can be no guarantee
that even when the Mann clients are paid that they will not contest the amount
or calculation of the royalties in a separate lawsuit.

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

     No matters were submitted during the fourth quarter of the fiscal year
covered by this report to a vote of security holders, through the solicitation
of proxies or otherwise.

EXECUTIVE OFFICERS OF THE REGISTRANT

     Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General
Instruction G (3) to Form 10-K the following information is included in Part I
of this Form 10-K.

     JOHN W. ELIAS has served as the Chief Executive Officer and Chairman of the
Board of the Company since November 1998. Mr. Elias is a member of the
Nominating Committee of the Board. From April 1993 to September 30, 1998, he
served in various senior management positions, including Executive Vice
President, of Seagull Energy Corporation, a company engaged in oil and natural
gas exploration, development and production and pipeline marketing. Prior to
April 1993 Mr. Elias served in various positions for more than 30 years,
including senior management positions with Amoco Corporation, a major integrated
oil and gas company. Mr. Elias has more than 40 years of experience in the oil
and natural gas exploration and production business. He is 62 years old.

     MICHAEL G. LONG has served as Senior Vice President and Chief Financial
Officer of the Company since December 1996. Mr. Long served as Vice
President-Finance of W&T Offshore, Inc., an oil and natural gas exploration and
production company, from July 1995 to December 1996. From May 1994 to July 1995,
he served as Vice President of the Southwest Petroleum Division for Chase
Manhattan Bank, N.A. Prior thereto, he served in various capacities with First
National Bank of Chicago, most recently that of Vice President and Senior
Corporate Banker of the Energy and Transportation Department, from March 1992 to
May 1994. Mr. Long received a B.A. in Political Science and a M.S. in Economics
from the University of Illinois. Mr. Long is 50 years old.

     JOHN O. TUGWELL has served as Senior Vice President Production since
December 2001 and prior to that served as Vice President of Production for the
Company since March 1997. He served as Senior Petroleum Engineer of the
Company's predecessor corporation since May 1995. From 1986 to May 1995, he held
various reservoir/production engineering positions with Shell Oil Company, most
recently that of Senior Reservoir

                                        23
<PAGE>

Engineer. Mr. Tugwell holds a B.S. in Petroleum Engineering from Louisiana State
University. Mr. Tugwell is a registered Professional Engineer in the State of
Texas. Mr. Tugwell is 39 years old.

SIGNIFICANT EMPLOYEES

     MARK J. GABRISCH has served as the Vice President of Land for the Company
since March 1997. From November 1994 to March 1997, he served in a similar
capacity with the Company's predecessor corporation. From 1985 to October 1994,
he was a landman, most recently a Senior Landman, for Shell Oil Company. Mr.
Gabrisch holds a B.S. in Petroleum Land Management from the University of
Houston. Mr. Gabrisch is 42 years old.

     JOHN O. HASTINGS, JR.  has served as the Vice President of Exploration for
the Company since March 1997 and prior thereto served in a similar capacity with
the Company's predecessor corporation since February 1994. From 1984 to February
1994, he was an exploration geologist with Shell Oil Company, serving as Senior
Geologist before his departure. Mr. Hastings holds a B.A. from Dartmouth in
Earth Sciences and a M.S. in Geology from Texas A&M University. He is 43 years
old.

     KIRSTEN A. HINK has served as Controller of the Company since December 31,
2000 and prior to that served as Assistant Controller from June 2000 to December
2000. She served as Controller of Benz Energy Inc., an oil and gas exploration
company, from June 1998 to June 2000. From September 1997 to June 1998, Mrs.
Hink served as a financial reporting accountant with Western Atlas, Inc. Mrs.
Hink received a B.S. in Accounting from Trinity University, San Antonio, Texas.
Mrs. Hink is a Certified Public Accountant in the State of Texas. She is 36
years old.

     C.W. MACLEOD has served as the Vice President Business Development and
Planning for the Company since January 2002. From November 1999 to December
2001, he was Vice President Investment Banking with Raymond James and
Associates, Inc. From February 1990 to October 1999, Mr. MacLeod was a principal
with Kirkpatrick Energy Associates, Inc., whose principal business was merger
and acquisition services, capital arrangement and analytical services for the
oil and gas producing industry. Mr. MacLeod was responsible for originating
corporate finance and research products for energy clients. His previous
experience includes positions as an independent petroleum geologist, a manager
of exploration and production for an independent oil and gas producer and
geologic positions with Ladd Petroleum Corporation and Resource Sciences
Corporation. Mr. MacLeod graduated from Eastern Michigan University with a B.S.
in Geology and earned his M.B.A. from the University of Tulsa. Mr. MacLeod is a
registered professional geologist in the state of Wyoming. He is 52 years old.

     ROBERT C. THOMAS has served as Vice President, General Counsel and
Corporate Secretary since March 1997. From February 1991 to March 1997, he
served in similar capacities for the Company's corporate predecessor. From 1988
to January 1991, he was associate and acting general counsel for Mesa Limited
Partnership in Amarillo, Texas. Mr. Thomas holds a B.S. degree in Finance and a
J.D. degree in Law from the University of Texas at Austin. He is 49 years old.

                                        24
<PAGE>

                                    PART II

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

     As of March 14, 2003, we estimate there were approximately 2,687 beneficial
holders of our Common Stock. Our Common Stock is listed on the NASDAQ National
Market ("NASDAQ") and traded under the symbol "EPEX". As of March 14, 2003, we
had 9,465,734 shares outstanding and our closing price on NASDAQ was $4.05 per
share. The following table sets forth, for the periods indicated, the high and
low closing sales prices for our Common Stock as listed on NASDAQ.

<Table>
<Caption>
                                                                 COMMON
                                                              STOCK PRICES
                                                              -------------
                                                              HIGH     LOW
                                                               ($)     ($)
                                                              -----   -----
<S>                                                           <C>     <C>
CALENDAR 2002
  First Quarter.............................................  5.84    4.77
  Second Quarter............................................  6.54    5.00
  Third Quarter.............................................  5.25    4.04
  Fourth Quarter............................................  4.27    2.80
CALENDAR 2001
  First Quarter.............................................  9.50    6.88
  Second Quarter............................................  9.45    5.50
  Third Quarter.............................................  7.10    4.05
  Fourth Quarter............................................  5.74    4.16
</Table>

     We have never paid a dividend, cash or otherwise, and do not intend to in
the foreseeable future. The payment of future dividends will be determined by
our Board of Directors in light of conditions then existing, including our
earnings, financial condition, capital requirements, restrictions in financing
agreements, business conditions and other factors. See ITEMS 1 AND
2. -- BUSINESS AND PROPERTIES -- "FORWARD LOOKING INFORMATION AND RISK
FACTORS -- We do not intend to pay dividends and our ability to pay dividends is
restricted".

                                        25
<PAGE>

ITEM 6.  SELECTED FINANCIAL DATA

     The following table sets forth selected financial data regarding the
Company as of and for each of the periods indicated. The following data should
be read in conjunction with "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and our financial statements and notes
thereto, which follow:

<Table>
<Caption>
                                                        YEAR ENDED DECEMBER 31,
                                          ----------------------------------------------------
                                            2002     2001(5)    2000(1)    1999(1)    1998(1)
                                          --------   --------   --------   --------   --------
                                                (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S>                                       <C>        <C>        <C>        <C>        <C>
OPERATIONAL DATA:
  Oil and natural gas revenue...........  $ 20,911   $ 29,811   $ 23,774   $ 14,486   $ 15,463
  Operating expenses:
     Oil and natural gas operating
       expenses including production and
       ad valorem taxes.................     3,831      5,001      3,955      3,039      3,376
     Depletion, depreciation and
       amortization.....................    10,427      9,378      7,641      8,512     10,002
     Impairment of oil and natural gas
       properties.......................        --         --         --         --     10,013
     Litigation settlement..............        --      3,547         --         --         --
     General and administrative
       expenses:
       Deferred compensation
          expense(2)....................       403       (497)     1,027        350        621
       Other general and
          administrative................     4,826      5,038      3,824      4,528      4,583
       Other charge.....................        --         --         --      1,688      2,898
                                          --------   --------   --------   --------   --------
          Total operating expenses......    19,487     22,467     16,447     18,117     31,493
                                          --------   --------   --------   --------   --------
  Operating income (loss)...............     1,424      7,344      7,327     (3,631)   (16,030)
     Interest expense, net..............      (228)      (215)      (172)      (130)       (90)
     Interest income....................        27        128         98         52        133
     Loss on sale of investment.........        --         --       (355)        --         --
                                          --------   --------   --------   --------   --------
  Income (loss) before income taxes and
     cumulative effect of accounting
     change.............................     1,223      7,257      6,898     (3,709)   (15,987)
                                          --------   --------   --------   --------   --------
     Income tax benefit (expense).......      (473)       819         --         --        983
                                          --------   --------   --------   --------   --------
  Income (loss) before cumulative effect
     of accounting change...............       750      8,076      6,898     (3,709)   (15,004)
     Cumulative effect of accounting
       change...........................        --         --         --         --      1,781
                                          --------   --------   --------   --------   --------
  Net income (loss).....................  $    750   $  8,076   $  6,898   $ (3,709)  $(13,223)
                                          ========   ========   ========   ========   ========
  Basic earnings (loss) per share: (3)
     Income (loss) before cumulative
       effect of accounting change......  $   0.08   $   0.87   $   0.75   $  (0.43)  $  (1.93)
     Cumulative effect of accounting
       change...........................        --         --         --         --       0.23
                                          --------   --------   --------   --------   --------
     Basic earnings (loss) per share....  $   0.08   $   0.87   $   0.75   $  (0.43)  $  (1.70)
                                          ========   ========   ========   ========   ========
  Diluted earnings (loss) per share: (3)
     Income (loss) before cumulative
       effect of accounting change......  $   0.08   $   0.83   $   0.74   $  (0.43)  $  (1.93)
     Cumulative effect of accounting
       change...........................        --         --         --         --       0.23
                                          --------   --------   --------   --------   --------
     Diluted earnings (loss) per
       share............................  $   0.08   $   0.83   $   0.74   $  (0.43)  $  (1.70)
                                          ========   ========   ========   ========   ========
  Basic weighted average number of
     shares outstanding(3)..............     9,384      9,281      9,183      8,680      7,759
</Table>

                                        26
<PAGE>

<Table>
<Caption>
                                                        YEAR ENDED DECEMBER 31,
                                          ----------------------------------------------------
                                            2002     2001(5)    2000(1)    1999(1)    1998(1)
                                          --------   --------   --------   --------   --------
                                                (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S>                                       <C>        <C>        <C>        <C>        <C>
  Diluted weighted average number of
     shares outstanding(3)..............     9,606      9,728      9,330      8,680      7,759
SELECT CASH FLOW DATA:
     Net income (loss)..................  $    750   $  8,076   $  6,898   $ (3,709)  $(13,223)
     Interest expense...................       228        215        172        130         90
     Income taxes.......................       473       (819)        --         --       (983)
     Depletion, depreciation and
       amortization.....................    10,427      9,378      7,641      8,512     10,002
                                          --------   --------   --------   --------   --------
  EBITDA(4).............................    11,878     16,850     14,711      4,933     (4,114)
     Other..............................       259        (85)     1,265      1,048     10,139
     Net changes in working capital.....    (1,729)     5,386     (6,330)      (373)     5,686
                                          --------   --------   --------   --------   --------
     Net cash provided by operating
       activities.......................  $ 10,408   $ 22,151   $  9,646   $  5,608   $ 11,711
                                          ========   ========   ========   ========   ========
  Capital expenditures..................  $(19,610)  $(28,989)  $(10,718)  $(14,588)  $(34,824)
  Other investing activities............       355         --      5,323      7,329      6,835
                                          --------   --------   --------   --------   --------
  Net cash used in investing
     activities.........................  $(19,255)  $(28,989)  $ (5,395)  $ (7,259)  $(27,989)
                                          ========   ========   ========   ========   ========
  Net cash provided by (used in)
     financing activities...............  $ 10,623   $  7,383   $ (4,003)  $  1,651   $ 12,500
                                          ========   ========   ========   ========   ========
</Table>

<Table>
<Caption>
                                                              AS OF DECEMBER 31,
                                                ----------------------------------------------
                                                 2002     2001      2000      1999      1998
                                                ------   -------   -------   -------   -------
                                                                (IN THOUSANDS)
<S>                                             <C>      <C>       <C>       <C>       <C>
SELECT BALANCE SHEET DATA:
  Working capital surplus (deficit)...........  $3,311   $   682   $ 2,879   $(4,977)  $(8,255)
  Property and equipment, net.................  75,682    66,853    47,242    45,976    47,259
  Total assets................................  85,576    76,024    57,961    55,613    56,006
  Long-term debt, including current
     maturities...............................  20,500    10,000     3,000     6,800    12,500
  Stockholders' equity........................  58,533    58,099    50,129    42,174    36,956
</Table>

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

(1) Certain prior year balances have been reclassified to conform to the current
    year presentation.

(2) Deferred compensation expense includes the amortization of compensation
    costs related to restricted stock grants and the non-cash charge or credit
    related to requirements under FASB Interpretation No. (FIN) 44, Accounting
    for Certain Transactions involving Stock Compensation. At December 31, 2000,
    a charge was required under FIN 44 when the daily average market price of
    our stock exceeded the strike price of certain options. At December 31,
    2001, our daily average market price was below the strike price of these
    options and as a result, a credit was required to reduce compensation
    expense except as it related to repriced options exercised in 2001. During
    2002, certain options and restricted stock were allowed to vest earlier than
    the original vesting date as part of a termination agreement. A charge under
    FIN 44 was required related to these transactions.

(3) Basic and diluted earnings (loss) per share has been computed based on the
    net income (loss) shown above and assuming the 4,701,361 shares of Common
    Stock issued in connection with the Combination (as defined below in ITEM 7.
    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
    OPERATIONS -- "General Overview") were outstanding for all periods prior to
    the Combination, effective March 3, 1997.

(4) EBITDA represents income (loss) before interest expense, income taxes,
    depletion, and depreciation and amortization. Our management believes that
    EBITDA may provide additional information often used by the investment
    community to assess our ability to meet our future requirements for debt
    service, capital expenditures and working capital. EBITDA is a financial
    measure commonly used in the oil and natural gas industry and should not be
    considered in isolation or as a substitute for net income, operating income,

                                        27
<PAGE>

    cash flows from operating activities or any other measure of financial
    performance presented in accordance with generally accepted accounting
    principles or as a measure of a company's profitability or liquidity.
    Because EBITDA excludes some, but not all, items that affect net income,
    this measure may vary among companies. The EBITDA data presented above may
    not be comparable to a similarly titled measure of other companies.

(5) As discussed in Note 2 to the Consolidated Financial Statements, effective
    January 1, 2001, we changed our method of accounting for derivative
    instruments.

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS

     The following is a review of our financial position and results of
operations for the periods indicated. Our Consolidated Financial Statements and
Supplementary Data and the related notes thereto contain detailed information
that should be referred to in conjunction with Management's Discussion and
Analysis of Financial Condition and Results of Operations.

GENERAL OVERVIEW

     We were organized as a Delaware corporation in August 1996 in connection
with our initial public offering (the "Offering") and the related combination of
certain entities that held interests in the Edge Joint Venture II (the "Joint
Venture") and certain other oil and natural gas properties, herein referred to
as the "Combination". In a series of combination transactions, we issued an
aggregate of 4,701,361 shares of common stock and received in exchange 100% of
the ownership interests in the Joint Venture and certain other oil and natural
gas properties. In March 1997, and contemporaneously with the Combination, we
completed the Offering of 2,760,000 shares of our common stock generating
proceeds of approximately $40 million, net of expenses.

     We have evolved over time from a prospect generation organization focused
solely on high-risk, high-reward exploration to a team driven organization
focused on a balanced program of exploration, exploitation, development and
acquisition of oil and natural gas properties. Following a top-level management
change in late 1998, a more disciplined style of business planning and
management was integrated into our technology-driven drilling activities. We
believe these changes in our strategy and business discipline will result in
continued growth in reserves, production and financial strength.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

     The preparation of financial statements in conformity with generally
accepted accounting principles in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues, expenses and disclosure of contingent assets and
liabilities in the accompanying financial statements. Changes in these estimates
could materially affect our financial position, results of operations or cash
flows. Key estimates used by management include revenue and expense accruals,
environmental costs, depreciation and amortization, asset impairment and fair
values of assets acquired. Significant accounting policies that we employ are
presented in the notes to the consolidated financial statements.

  REVENUE RECOGNITION

     We recognize oil and natural gas revenue from our interests in producing
wells as oil and natural gas is produced and sold from those wells. Oil and
natural gas sold by us is not significantly different from our share of
production.

  OIL AND NATURAL GAS PROPERTIES

     Investments in oil and natural gas properties are accounted for using the
full cost method of accounting. All costs associated with the exploration,
development and acquisition of oil and natural gas properties, including
salaries, benefits and other internal costs directly attributable to these
activities are capitalized within a cost center. Our oil and natural gas
properties are located within the United States of America that constitutes one
cost center.

                                        28
<PAGE>

     In accordance with the full cost method of accounting, we capitalized a
portion of interest expense on borrowed funds. Employee related costs that are
directly attributable to exploration and development activities are also
capitalized. These costs are considered to be direct costs based on the nature
of their function as it relates to the exploration and development function.

     Oil and natural gas properties are amortized using the unit-of-production
method using estimates of proved reserve quantities. Investments in unproved
properties are not amortized until proved reserves associated with the prospects
can be determined or until impairment occurs. Unevaluated properties are
evaluated periodically for impairment on a property-by-property basis. If the
results of an assessment indicated that an unproved property is impaired, the
amount of impairment is added to the proved oil and natural gas property costs
to be amortized. The amortizable base includes estimated future development
costs and, where significant, dismantlement, restoration and abandonment costs.

     In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 141, "Business
Combinations," which requires the use of the purchase method of accounting for
business combinations initiated after June 30, 2001 and eliminates the
pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142,
"Goodwill and Other Intangible Assets," which discontinues the practice of
amortizing goodwill and indefinite lived intangible assets and initiates an
annual review of impairment. The new standard also requires that, at a minimum,
all intangible assets be aggregated and presented as a separate line item in the
balance sheet. The adoption of SFAS No. 141 and 142 had no impact on our
financial position or results of operations

     A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and 142 to companies in the extractive industries,
including oil and gas companies. The issue is whether SFAS No. 141 requires
registrants to classify the costs of mineral rights associated with extracting
oil and gas as intangible assets in the balance sheet, apart from other
capitalized oil and gas property costs, and provide specific footnote
disclosures. Historically, we have included the costs of mineral rights
associated with extracting oil and gas as a component of oil and gas properties.
If it is ultimately determined that SFAS No. 141 requires oil and gas companies
to classify costs of mineral rights associated with extracting oil and gas as a
separate intangible assets line item on the balance sheet, we would be required
to reclassify approximately $8.8 million and $5.5 million at December 31, 2002
and 2001, respectively, out of oil and gas properties and into a separate
intangible assets line item. These costs include those to acquire contract based
drilling and mineral use rights such as delay rentals, lease bonuses,
commissions and brokerage fees, and other leasehold costs. Our 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 full cost
accounting rules, as allowed by SFAS No. 142. Further, we do not believe the
classification of the costs of mineral rights associated with extracting oil and
gas as intangible assets would have any impact on our compliance with covenants
under our debt agreements.

     In addition, the capitalized costs of oil and natural gas properties are
subject to a "ceiling test," whereby to the extent that such capitalized costs
subject to amortization in the full cost pool (net of depletion, depreciation
and amortization and related deferred taxes) exceed the present value (using a
10% discount rate) of estimated future net after-tax cash flows from proved oil
and natural gas reserves, such excess costs are charged to operations. Once
incurred, an impairment of oil and natural gas properties is not reversible at a
later date. Impairment of oil and natural gas properties is assessed on a
quarterly basis in conjunction with our quarterly filings with the Securities
and Exchange Commission. No adjustment related to the ceiling test was required
during the years ended December 31, 2002, 2001, or 2000.

     Sales of proved and unproved properties are accounted for as adjustments of
capitalized costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves. Abandonment of oil and natural gas properties are accounted for as
adjustments of capitalize costs with no loss recognized.

  OIL AND NATURAL GAS RESERVES

     Reserve estimates of new discoveries are more imprecise than those of
properties with a production history. Accordingly, the reserve estimates of new
discoveries are subject to change as additional information becomes available.
Proved reserves are the estimated quantities of crude oil, condensate and
natural gas that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from
                                        29
<PAGE>

known reservoirs under existing economic and operating conditions at the end of
the respective years. Proved developed reserves are those reserves expected to
be recovered through existing equipment and operating methods.

  DERIVATIVES AND HEDGING ACTIVITIES

     Due to the instability of oil and natural gas prices, we have entered into,
from time to time, price risk management transactions (e.g., swaps, collars and
floors) for a portion of our oil and natural gas production to achieve a more
predictable cash flow, as well as to reduce exposure from price fluctuations.
While the use of these arrangements limits the benefit to us of increases in the
price of oil and natural gas, it also limits the downside risk of adverse price
movements. Our hedging arrangements typically apply to only a portion of our
production, providing only partial price protection against declines in oil and
natural gas prices. We account for these transactions as hedging activities and,
accordingly, realized gains and losses are included in oil and natural gas
revenue during the period the hedged production occurs.

     We formally assess, both at the hedge's inception and on an ongoing basis,
whether the derivatives that are used in hedging transactions are expected to be
highly effective in offsetting changes in cash flows of hedged transactions. In
the event it is determined that the use of a particular derivative may not be or
has ceased to be effective in pursuing a hedging strategy, hedge accounting is
discontinued prospectively.

     Our revenue, profitability and future rate of growth and ability to borrow
funds or obtain additional capital, and the carrying value of our properties,
are substantially dependent upon prevailing prices for oil and natural gas.
These prices are dependent upon numerous factors beyond our control, such as
economic, political and regulatory developments and competition from other
sources of energy. A substantial or extended decline in oil and natural gas
prices could have a material adverse effect on our financial condition, results
of operations and access to capital, as well as the quantities of oil and
natural gas reserves that we may economically produce.

  STOCK-BASED COMPENSATION

     We account for stock compensation plans under the intrinsic value method of
Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued
to Employees." No compensation expense is recognized for stock options that had
an exercise price equal to the market value of their underlying common stock on
the date of grant. As allowed by SFAS No. 123, "Accounting for Stock Based
Compensation," we have continued to apply APB Opinion No. 25 for purposes of
determining net income. In December 2002, the FASB issued SFAS No. 148,
"Accounting for Stock Based Compensation -- Transition and Disclosure -- an
amendment of FASB Statement No. 123" to provide alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. Additionally, the statement amend the
disclosure requirements of SFAS No. 123 to require prominent disclosures in both
annual and interim financial statements about the method of accounting for
stock-based compensation and the effect of the method used on reported results.

     We are also subject to reporting requirements of FASB Interpretation No.
(FIN) 44, "Accounting for Certain Transactions involving Stock Compensation"
that requires a non-cash charge to deferred compensation expense if the market
price of our common stock at the end of a reporting period is greater than the
exercise price of certain stock options. After the first such adjustment is
made, each subsequent period is adjusted upward or downward to the extent that
the market price exceeds the exercise price of the options. The charge is
related to non-qualified stock options granted to employees and directors in
prior years conjunction with the repricing.

RESULTS OF OPERATIONS

  YEAR ENDED DECEMBER 31, 2002 COMPARED TO THE YEAR ENDED DECEMBER 31, 2001

  Revenue and Production

     Oil and natural gas revenue decreased 30% from $29.8 million in 2001 to
$20.9 million in 2002. For 2002, natural gas production comprised 76% of total
production and contributed 79% of total revenue, oil and condensate comprised
10% of total production and contributed 13% of total revenue, and NGL production
                                        30
<PAGE>

comprised 14% of total production and contributed 8% of total revenue. For 2001,
natural gas production comprised 86% of total production and 88% of total
revenue, while oil and condensate production accounted for 10% of total
production and 9% of revenue, and NGL production comprised 4% of total
production and 3% of total revenue.

     The following table summarizes production volumes, average sales prices and
operating revenue for our oil and natural gas operations for the years ended
December 31, 2002 and 2001.

<Table>
<Caption>
                                                                 2002 PERIOD COMPARED TO
                                                                       2001 PERIOD
                                           DECEMBER 31,          ------------------------
                                     -------------------------    INCREASE     % INCREASE
                                       2002(2)        2001       (DECREASE)    (DECREASE)
                                     -----------   -----------   -----------   ----------
<S>                                  <C>           <C>           <C>           <C>
PRODUCTION VOLUMES:
  Natural gas (Mcf)................    5,266,390     6,198,871      (932,481)     (15)%
  Oil and condensate (Bbls)........      119,527       115,728         3,799        3%
  Natural gas liquids (Bbls).......      161,301        45,701       115,600      253%
  Natural gas equivalent (Mcfe)....    6,951,357     7,167,445      (216,088)      (3)%
AVERAGE SALES PRICE:
  Natural gas ($ per Mcf)(1).......  $      3.14   $      4.23   $     (1.09)     (26)%
  Oil and condensate ($ per Bbl)...  $     22.88   $     23.94   $     (1.06)      (4)%
  Natural gas liquids ($ per
     Bbl)..........................  $     10.31   $     17.74   $     (7.43)     (42)%
  Natural gas equivalent ($ per
     Mcfe)(1)......................  $      3.01   $      4.16   $     (1.15)     (28)%
OPERATING REVENUE:
  Natural gas(1)...................  $16,513,096   $26,229,567   $(9,716,471)     (37)%
  Oil and condensate...............    2,734,491     2,770,825       (36,334)      (1)%
  Natural gas liquids..............    1,663,707       810,525       853,182      105%
                                     -----------   -----------   -----------
Total(1)...........................  $20,911,294   $29,810,917   $(8,899,623)     (30)%
                                     ===========   ===========   ===========
</Table>

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

(1) Includes the effect of hedging.

(2) Results for 2002 were favorably impacted by the recognition in the second
    quarter of 2002 of revenue associated with underaccruals in prior periods.
    This adjustment resulted in 142 MMcfe of additional production and $577,200
    additional revenue.

     Natural gas revenue decreased 37% from $26.2 million for the year ended
December 31, 2001 to $16.5 million for 2002. Significantly lower realized prices
coupled with a decline in production for the year were slightly offset by a
lower realized hedge loss. The average natural gas sales price for production in
2002 was $3.20 per Mcf, exclusive of hedging activity, compared to $4.38 per Mcf
for 2001, exclusive of hedging activity. This decrease in average price received
resulted in decreased revenue of approximately $6.2 million (based on current
year production). Included within natural gas revenue for the year ended
December 31, 2002 and 2001 was $(0.3) million and $(0.9) million, respectively,
representing losses from hedging activity. These losses decreased the effective
natural gas sales price by $(0.06) per Mcf and $(0.15) per Mcf, for the years
ended December 31, 2002 and 2001, respectively. For the year ended December 31,
2002, natural gas production decreased 15% from 17.0 Mcf/d in 2001 to 14.4 Mcf/d
in 2002 due primarily to natural declines in production at our Austin Field and
O'Connor Ranch properties, partially offset by increased production from new
wells drilled in late 2001 and in 2002. This decrease in production compared to
the prior year resulted in a decrease in revenue of approximately $4.1 million
(based on 2001 comparable period prices).

     Revenue from the sale of oil and condensate totaled $2.7 million for the
year ended December 31, 2002, a decrease of 1% from the prior year total of $2.8
million. The average realized price for oil and condensate for the year ended
December 31, 2002 was $22.88 per barrel compared to $23.94 per barrel in 2001.
Lower average prices for the year 2002 resulted in a decrease in revenue of
approximately $127,300 (based on current year production). Production volumes
for oil and condensate increased 3% to 327 Bbls/d for the year ended December
31, 2002 compared to 317 Bbls/d for the same prior year period. The increase in
oil and condensate

                                        31
<PAGE>

production resulted in an increase in revenue of approximately $91,000 (based on
2001 comparable period average prices).

     Revenue from the sale of NGLs totaled $1.7 million for the year ended
December 31, 2002, an increase of 105% from the 2001 total of $0.8 million.
Production volumes for NGLs increased 253%, from 125 Bbls/d for the year ended
December 31, 2001 to 442 Bbls/d for the year ended December 31, 2002. The
increase in NGL production increased revenue by $2.1 million (based on 2001
comparable period average prices). This increase in production was largely due
to increased liquids processing stemming from Gato Creek Field (Webb County,
Texas), an acquisition made in late 2001. Lower average realized prices for the
year ended December 31, 2002 resulted in a decrease in revenue of $1.2 million
(based on current year production). The average realized price for NGLs for the
year ended December 31, 2002 was $10.31 per barrel compared to $17.74 per barrel
for the same period in 2001.

  Costs and Operating Expenses

     Operating expenses for the year ended December 31, 2002 totaled $2.2
million compared to $2.8 million in the same period of 2001, a decrease of 22%.
Current year results were impacted by lower well control insurance and salt
water disposal costs, partially offset by higher treating costs incurred in 2002
compared to the prior year. Operating expenses averaged $0.32 per Mcfe for the
year ended December 31, 2002 compared to $0.39 per Mcfe for the prior year
period.

     Severance and ad valorem taxes for the year ended December 31, 2002
decreased 26% from $2.2 million in 2001, to $1.6 million in 2002. Severance tax
expense for 2002 was 39% lower than the prior year period as a result of lower
revenue as well as severance tax exemption credits on certain properties. For
the year ended December 31, 2002, severance tax expense was approximately 5.7%
of total revenue compared to 6.5% of total revenue for the comparable 2001
period. Ad valorem costs, however, increased from approximately $222,000 in 2001
to over $419,000 in 2002 due primarily to additional costs on the Ibarra and La
Jollo Parr properties as well as the Gato Creek properties which were acquired
at year-end 2001. On an equivalent basis, severance and ad valorem taxes
averaged $0.23 per Mcfe and $0.30 per Mcfe for the years ended December 31, 2002
and 2001, respectively.

     Depletion, depreciation and amortization expense ("DD&A") for the year
ended December 31, 2002 totaled $10.4 million compared to $9.4 million for the
year ended December 31, 2001. Full cost depletion on our oil and natural gas
properties totaled $9.7 million for 2002 compared to $8.7 million in 2001.
Depletion expense on a unit of production basis for the year ended December 31,
2002 was $1.40 per Mcfe, 15% higher than the 2001 rate of $1.22 per Mcfe. The
higher depletion rate per Mcfe resulted in an increase in depletion expense of
$1.2 million. For the year ended December 31, 2002, lower oil and natural gas
production compared to the prior year period resulted in a decrease in depletion
expense of $0.2 million. The increase in the depletion rate was primarily due to
a higher amortizable base in 2002 compared to the prior year.

     In December 2001, we recorded costs of $3.5 million related to the
settlement of our litigation with BNP.

     Deferred compensation expense consists of costs reported in accordance with
FASB Interpretation No. (FIN) 44, Accounting for Certain Transactions involving
Stock Compensation and amortization related to restricted stock awards. A FIN 44
charge of $3,385 was incurred for the year ended December 31, 2002 compared to a
credit of $(850,281) in the comparable prior year period. FIN 44 requires, among
other things, a non-cash charge to compensation expense if the price of our
common stock on the last trading day of a reporting period is greater than the
exercise price of certain options. FIN 44 could also result in a credit to
compensation expense to the extent that the trading price declines from the
trading price as of the end of the prior period, but not below the exercise
price of the options. We adjust deferred compensation expense upward or downward
on a monthly basis based on the trading price at the end of each such period as
necessary to comply with FIN 44. We are required to report under this rule as a
result of non-qualified stock options granted to employees and directors in
prior years and re-priced in May of 1999, as well as certain options newly
issued in conjunction with the repricing. Amortization related to restricted
stock awards granted during 2002 and 2001 totaled $399,249 and $353,371,
respectively.

     Other general and administrative expenses ("G&A") for the year ended
December 31, 2002, which excludes the deferred compensation expense discussed
above, totaled $4.8 million, a 4% decrease from the

                                        32
<PAGE>

2001 total of $5.0 million, due primarily to bad debt expense of $525,000
reserved in 2001. In addition, 2002 salaries and benefits were seven percent
lower than 2001 costs. Offsetting these lower costs were higher professional
service fees (primarily legal costs and audit fees), higher officers and
directors insurance costs and higher franchise taxes for 2002 compared to 2001.
For the years ended December 31, 2002 and 2001, overhead reimbursement fees
reduced G&A costs by $208,201 and $137,184, respectively. Other G&A on a unit of
production basis for the year ended December 31, 2002 was $0.69 per Mcfe
compared to $0.70 per Mcfe for the comparable 2001 period. We believe that lower
lease costs for our new headquarters will have a positive impact on G&A in 2003.
See Part I -- Business and Properties -- Office and Equipment.

     Included in other income (expense) was interest expense of $227,759 for the
year ended December 31, 2002 compared to $214,619 in the same 2001 period.
Interest expense, including facility fees, was $766,693 for the year 2002 on
weighted average debt of $15.4 million compared to interest expense of $137,623
on weighted average debt of approximately $0.7 million for the same prior year
period. Capitalized interest for the year ended December 2002 totaled $623,413
compared to $24,402 in the prior year. Also included in interest expense for the
years ended December 31, 2002 and 2001 was $84,479 and $101,398, respectively,
representing amortization of deferred loan costs associated with a new credit
facility.

     Interest income totaled $26,954 for the year ended December 31, 2002
compared to $127,717 for the same period in 2001. The decrease in interest
income is due primarily to the overall decrease in funds invested in overnight
money market funds.

     An income tax provision was recorded for the year ended December 31, 2002
of $473,060. As of December 31, 2002, approximately $27.4 million of net
operating loss carryforwards have been accumulated that begin to expire in 2012.
For the year ended December 31, 2001, an income tax benefit of $818,897 was
recorded as a result of reversing a valuation reserve. Currently, we do not
anticipate a federal tax liability or making federal tax payments in 2003.

     For the year ended December 31, 2002, the Company had net income of $0.7
million, or $0.08 basic earnings per share, as compared to net income of $8.1
million, or $0.87 basic earnings per share, in 2001. Weighted average shares
outstanding increased from approximately 9.3 million for the year ended December
31, 2001 to 9.4 million in the comparable 2002 period. The increase was due
primarily to options exercised and vesting of restricted stock during 2002.

  YEAR ENDED DECEMBER 31, 2001 COMPARED TO THE YEAR ENDED DECEMBER 31, 2000

  Revenue and Production

     Oil and natural gas revenue increased 25% from $23.8 million in 2000 to
$29.8 million in 2001. For 2001, natural gas production comprised 86% of total
production and contributed 88% of total revenue, oil and condensate comprised
10% of total production and contributed 9% of total revenue, and NGL's comprised
4% of total production and contributed 3% of total revenue. For 2000, natural
gas production comprised 83% of total production and 84% of total revenue while
oil and condensate production accounted for 9% of total production and 11% of
revenue and NGLs production comprised 8% of total production and 5% of oil and
gas revenue.

                                        33
<PAGE>

     The following table summarizes production volumes, average sales prices and
operating revenue for our oil and natural gas operations for the years ended
December 31, 2001 and 2000.

<Table>
<Caption>
                                                                     2001 PERIOD COMPARED
                                                                        TO 2000 PERIOD
                                             DECEMBER 31,          ------------------------
                                       -------------------------    INCREASE     % INCREASE
                                          2001          2000       (DECREASE)    (DECREASE)
                                       -----------   -----------   -----------   ----------
<S>                                    <C>           <C>           <C>           <C>
PRODUCTION VOLUMES:
  Natural gas (Mcf)..................    6,198,871     5,206,236       992,635           19%
  Oil and condensate (Bbls)..........      115,728        96,925        18,803           19%
  Natural gas liquids (Bbls).........       45,701        76,835       (31,134)         (41)%
  Natural gas equivalent (Mcfe)......    7,167,445     6,248,796       918,649           15%
AVERAGE SALES PRICE:
  Natural gas ($ per Mcf)(1).........  $      4.23   $      3.84   $      0.39           10%
  Oil and condensate ($ per
     Bbl)(1).........................  $     23.94   $     26.16   $     (2.22)          (8)%
  Natural gas liquids ($ per Bbl)....  $     17.74   $     16.37   $      1.37            8%
  Natural gas equivalent ($ per
     Mcfe)(1)........................  $      4.16   $      3.80   $      0.36            9%
OPERATING REVENUE:
  Natural gas(1).....................  $26,229,567   $19,980,704   $ 6,248,863           31%
  Oil and condensate(1)..............    2,770,825     2,536,028       234,797            9%
  Natural gas liquids................      810,525     1,257,684      (447,159)         (36)%
                                       -----------   -----------   -----------
Total(1).............................  $29,810,917   $23,774,416   $ 6,036,501           25%
                                       -----------   -----------   -----------
</Table>

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

(1) Includes the effect of hedging.

     Natural gas revenue increased 31% from $20.0 million for the year ended
December 31, 2000 to $26.2 million for 2001 due primarily to increased
production and the favorable impact of higher natural gas prices. For the year
ended December 31, 2001, natural gas production increased 19% from 14.2 Mcf/d in
2000 to 17.0 Mcf/d in 2001 resulting in an increase in revenue of approximately
$4.1 million (based on 2000 comparable period prices). The average natural gas
sales price for production in 2001 was $4.38 per Mcf, exclusive of hedging
activity, compared to $4.14 per Mcf for 2000, exclusive of hedging activity.
This increase in average price received resulted in increased revenue of
approximately $1.5 million (based on current year production). Included within
natural gas revenue for the year ended December 31, 2001 and 2000 was $(0.9)
million and $(1.5) million, respectively, representing losses from hedging
activity. These losses decreased the effective natural gas sales price by
$(0.15) per Mcf and $(0.30) per Mcf, for the years ended December 31, 2001 and
2000, respectively.

     Revenue from the sale of oil and condensate totaled $2.8 million for the
year ended December 31, 2001, an increase of 9% from the prior year total of
$2.5 million. The year ended December 31, 2000 included net losses from oil
hedge activity of $223,454. No oil hedges were in place for 2001. Production
volumes for oil and condensate increased 19% to 317 Bbls/d for the year ended
December 31, 2001 compared to 265 Bbls/d for the same prior year period. The
increase in oil and condensate production caused an increase in revenue of
approximately $535,300 (based on 2000 comparable period average prices before
hedges). The average price received for oil and condensate for the year ended
December 31, 2001 was $23.94 per barrel compared to $28.47 per barrel, excluding
the impact of net oil hedge losses of $(2.31) per barrel, in 2000. Lower average
prices for the year 2001 resulted in a decrease in revenue of $524,000 (based on
current year production).

     Revenue from the sale of NGLs totaled $0.8 million for the year ended
December 31, 2001, a decrease of 36% from the 2000 total of $1.3 million.
Production volumes for NGLs for the year ended December 31, 2001 decreased 41%,
from 210 Bbls/d to 125 Bbls/d, as compared to the year ended December 31, 2000.
The decrease in NGL production decreased revenue by $509,600 (based on 2000
comparable period average prices). This decrease in production was largely due
to high natural gas prices decreasing the economic value of NGL's and a
resulting decision by management not to process our gas during several months of
2001. Favorable pricing for the year ended December 31, 2001 resulted in an
increase in revenue of $62,500 (based
                                        34
<PAGE>

on current year production). The average realized price for NGLs for the year
ended December 31, 2001 was $17.74 per barrel compared to $16.37 per barrel for
the same period in 2000.

     Production of oil and natural gas was significantly impacted by our
drilling results in the second half of 2000 and in 2001. We successfully drilled
and completed 17 gross (7.081 net) wells in the year ended December 31, 2001
that added additional production and revenue for 2001. Gas production increases
were due primarily to the drilling of, and strong performance from, the O'Connor
Ranch wells, the Ibarra and La Jolla Parr wells on our La Jolla prospect, the
Mire #1 well on our Horeb prospect and the Robertson #1 well on our Duson Frio
prospect. Partially offsetting the favorable results of drilling were production
declines on our older wells, primarily the Margo #1 and #2 wells.

  Costs and Operating Expenses

     Operating expenses for the year ended December 31, 2001 totaled $2.8
million compared to $2.0 million in the same period of 2000, an increase of 44%.
Current year results were impacted by the increased number of wells operating in
2001 compared to the prior year as well as higher treating costs at the Austin
facility for a portion of 2001, higher salt water disposal costs on our older
wells, and higher well control insurance costs incurred in 2001 compared to the
prior year. Operating expenses averaged $0.39 per Mcfe for the year ended
December 31, 2001 compared to $0.31 per Mcfe for the prior year period. The
increase in operating expenses on a Mcfe basis was due to the factors resulting
in an overall increase in operating expenses described previously.

     Severance and ad valorem taxes for the year ended December 31, 2001
increased 9% from $2.0 million in 2000, to $2.2 million in 2001, due to higher
severance taxes paid on the increased revenue, primarily in the first quarter of
2001. On an equivalent basis, severance and ad valorem taxes were $0.30 per Mcfe
and $0.32 per Mcfe for the years ended December 31, 2001 and 2000, respectively.

     Depletion, depreciation and amortization expense ("DD&A") for the year
ended December 31, 2001 totaled $9.4 million compared to $7.6 million for the
year ended December 31, 2000. Full cost DD&A on our oil and natural gas
properties totaled $8.7 million for 2001 compared to $7.0 million in 2000.
Depletion expense on a unit of production basis for the year ended December 31,
2001 was $1.22 per Mcfe, 10% higher than the 2000 rate of $1.11 per Mcfe. The
higher depletion rate per Mcfe resulted in an increase in depletion expense of
$0.8 million. For the year ended December 31, 2001, higher oil and natural gas
production compared to the prior year period resulted in an increase in
depletion expense of $1.0 million. The increase in the depletion rate was
primarily due to a higher amortizable base in 2001 compared to the prior year.

     In December 2001, we recorded costs of $3.5 million related to the
settlement of our litigation with BNP.

     Deferred compensation expense consists of costs reported in accordance with
FIN 44 and amortization related to restricted stock awards. A FIN 44 credit of
$(850,281) was incurred for the year ended December 31, 2001 compared to a
charge of $899,548 in the comparable prior year period. Amortization related to
restricted stock awards granted during 2002 and 2001 totaled $353,371 and
$127,946, respectively.

     Other general and administrative expenses ("G&A") for the year ended
December 31, 2001, which excludes the deferred compensation expense discussed
above, totaled $5.0 million, a 32% increase from the 2000 total of $3.8 million.
The increase in costs was due primarily to bad debt expense of $525,000 reserved
in 2001 ($225,000 of which related to purchases by an Enron affiliate), costs of
$100,000 to purchase options from a former employee, higher salaries and related
benefits, and higher legal and audit fees. For the years ended December 31, 2001
and 2000, overhead reimbursement fees of approximately $137,200 and $120,300,
respectively, reduced G&A costs. Other G&A on a unit of production basis for the
year ended December 31, 2001 was $0.70 per Mcfe ($0.62 per Mcfe excluding the
bad debt expense and the purchase of options) compared to $0.61 per Mcfe for the
comparable 2000 period.

     Included in other income (expense) was interest expense of $214,619 for the
year ended December 31, 2001 compared to $171,783 in the same 2000 period.
Interest expense, including facility fees, was $137,623 for the year 2001 on
weighted average debt of $0.7 million compared to interest expense of $546,340
on weighted average debt of approximately $5.6 million for the same prior year
period. Also included in interest expense for the years ended December 31, 2001
and 2000 was $101,398 and $24,720, respectively, representing amortization of
deferred loan costs associated with a new credit facility. Capitalized interest
for the year ended
                                        35
<PAGE>

December 31, 2001 totaled $24,402 compared to $399,277 in the prior year. The
reduction in capitalized interest resulted from lower interest costs incurred
during the year ended December 31, 2001 compared to the same prior year period.
Although gross interest expense has decreased compared to the prior year, the
effect of less interest being capitalized to oil and natural gas properties has
resulted in higher net interest costs reported in our results of operations.

     Interest income totaled $127,717 for the year ended December 31, 2001
compared to $97,860 for the same period in 2000. The increase in interest income
is due to the overall increase in funds invested in overnight money market
funds.

     Other income (expense) for the year ended December 31, 2000 also included a
loss on the sale of our investment in Frontera of $(354,733) or $(0.04) per
share.

     An income tax benefit was recorded for the year ended December 31, 2001 of
$818,897. As of December 31, 2001, approximately $18.2 million of net operating
loss carryforwards have been accumulated that begin to expire in 2012. Based on
our year-end 2001 projections, we determined that we would fully realize our
recorded tax assets. Accordingly, $818,897 in associated valuation reserves was
reversed in 2001. Future financial statement income will necessitate income tax
provisions at our effective rate. For the year ended December 31, 2000, no tax
expense or benefit was recorded because an allowance was provided to offset the
tax benefits of certain tax assets.

     For the year ended December 31, 2001, the Company had net income of $8.1
million, or $0.87 basic earnings per share, as compared to net income of $6.9
million, or $0.75 basic earnings per share, in 2000.

     Weighted average shares outstanding increased from approximately 9.2
million for the year ended December 31, 2000 to 9.3 million in the comparable
2001 period. The increase was due primarily to options exercised and vesting of
restricted stock during 2001.

  Liquidity and Capital Resources

     In March 1997, we completed the Offering of 2,760,000 shares of our common
stock at a public offering price of $16.50 per share. The Offering provided us
with proceeds of approximately $40 million, net of expenses. We used
approximately $12.7 million to repay our long-term outstanding indebtedness
incurred under our revolving credit facility in place at the time, subordinated
loans and equipment loans. The remaining proceeds from the Offering, together
with cash flows from operations, were used to fund capital expenditures,
commitments, and other working capital requirements and for general corporate
purposes.

     On May 6, 1999, we completed a "Private Offering" of 1,400,000 shares of
common stock at a price of $5.40 per share. We also issued warrants, which were
purchased for $0.125 per warrant, to acquire an additional 420,000 shares of
common stock at $5.35 per share and are exercisable through May 6, 2004. At our
election, the warrants may be called at a redemption price of $0.01 per warrant
at any time after any date at which the average daily per share closing bid
price for the immediately proceeding 20 consecutive trading days exceeds $10.70.
No warrants have been exercised as of December 31, 2002. Total proceeds, net of
offering costs, were approximately $7.4 million of which $4.9 million was used
to repay debt under our revolving credit facility in place at the time, with the
remainder being utilized to satisfy working capital requirements and to fund a
portion of our exploration program. Pursuant to the terms of the private
placement, we filed a registration statement with the Commission registering the
resale of the shares of Common Stock and the warrants sold in the private
placement, as well as the resale of any shares of Common Stock issued pursuant
to such warrants.

     We had cash and cash equivalents at December 31, 2002 of $2,568,176
consisting primarily of short-term money market investments, as compared to
$793,287 at December 31, 2001. Working capital was $3.3 million as of December
31, 2002, as compared to $0.7 million at December 31, 2001.

     Cash flows provided by operating activities were $10.4 million, $22.2
million and $9.6 million, for the years ended December 31, 2002, 2001, and 2000,
respectively. The decrease in cash flows provided by operating activities in
2002 compared to 2001 was due primarily to lower net income in 2002, a larger
decrease in accrued liabilities for 2002 and a lower decrease in accounts
receivable for 2002 compared to 2001. The significant increase in cash flows
provided by operating activities for the year ended December 31, 2001

                                        36
<PAGE>

compared to 2000 was primarily due to higher net income in 2001, lower accounts
receivable balance and higher accrued liabilities at December 31, 2001 compared
to the prior year.

     We reinvest a substantial portion of our cash flows in our drilling,
acquisition, land and geophysical activities. As a result, we used $19.3 million
in investing activities during 2002. Capital expenditures of $19.6 million for
the year ended December 31, 2002, were partially offset by $0.4 million in
proceeds from the sale of oil and gas properties during 2002. Capital
expenditures of $12.7 million were attributable to the drilling of 13 gross
wells, 11 of which were successful. Acquisition costs totaled $1.4 million for
the year ended December 31, 2002, and an additional $5.5 million in expenditures
was attributable to land holdings, including $1.0 million for increased seismic
data and other geological and geophysical expenditures. The remaining capital
expenditures were associated with computer hardware and office equipment.

     During the year ended December 31, 2001, we used $29.0 million in investing
activities, all of which were capital expenditures. Capital expenditures of
$15.9 million were attributed to drilling 22 gross wells, 17 of which were
successful. Acquisition costs totaled $6.7 million for the year ended December
31, 2001, and an additional $6.0 million was attributable to land holdings,
including $2.6 million for seismic data and other geological and geophysical
expenditures. The remaining capital expenditures were associated with computer
hardware and office equipment.

     During the year ended December 31, 2000, we used $5.4 million of cash in
investing activities including capital expenditures of approximately $10.7
million. Capital expenditures of $5.7 million were attributed to the drilling of
26 gross wells, 24 of which were successful. Capital expenditures of $3.2
million were attributable to increased land holdings and $1.8 million was
attributable to increased seismic data and other geologic and geophysical
expenditures. These expenditures were offset by proceeds from the sale of oil
and natural gas properties of $1.8 million and net proceeds from the sale of our
investment in Frontera of $3.5 million.

     We currently anticipate capital expenditures in 2003 to be approximately
$15.3 million. Approximately $10.7 million is allocated to our expected drilling
and production activities; $1.9 million is allocated to land and seismic
activities; and $2.7 million relates to capitalized interest and G&A and other.
We plan to fund these expenditures largely from cash flow from operations plus
some modest incremental borrowings. We have not explicitly budgeted for
acquisitions; however, we do expect to spend considerable effort evaluating
acquisition opportunities. We expect to fund acquisitions through traditional
reserve-based bank debt and/or the issuance of equity and, if required, through
additional debt and equity financings.

     Cash flows provided by financing activities totaled $10.6 million for the
year ended December 31, 2002 including $11.0 million in borrowings and $0.5
million in repayments under our current credit facility. In addition, we
received $122,653 in proceeds from the issuance of common stock related to
options exercised in 2002. Cash flows provided by financing activities in 2001
were $7.4 million, including borrowings of $11.0 million and repayments of $4.0
million under our credit facility. In addition, we received $390,421 in proceeds
from the issuance of common stock related to options exercised in 2001. Cash
flows used in financing activities in 2000 were $(4.0) million, including
borrowings of $5.4 million and repayments of $9.2 million under our credit
facility and the predecessor facility. We incurred loan costs of approximately
$202,900 during 2000 in establishing our new credit facility.

     Due to our active exploration, development and acquisition activities, we
have experienced and expect to continue to experience substantial working
capital requirements. We intend to fund our 2003 capital expenditures,
commitments and working capital requirements through cash flows from operations,
and to the extent necessary other financing activities. The projected 2003 cash
flows from operations are estimated to be sufficient to fund our budgeted
exploration and development program. We believe we will be able to generate
capital resources and liquidity sufficient to fund our capital expenditures and
meet such financial obligations as they come due. In the event such capital
resources are not available to us, our drilling and other activities may be
curtailed. See ITEMS 1 AND 2. -- "BUSINESS AND PROPERTIES -- FORWARD LOOKING
INFORMATION AND RISK FACTORS -- Our operations have significant capital
requirements."

     CREDIT FACILITY

     In October 2000, the Company entered into a new credit facility (the
"Credit Facility") with a bank. Borrowings under the Credit Facility bear
interest at a rate equal to prime plus 0.50% or LIBOR plus 2.75%.

                                        37
<PAGE>

As of December 31, 2002, $20.5 million in borrowings were outstanding under the
Credit Facility. The Credit Facility matures October 6, 2004 and is secured by
substantially all of the Company's assets.

     Originally the borrowing base under the Credit Facility was $5 million and
was subject to automatic reductions at a rate of $300,000 per month beginning
October 31, 2000. In March 2001, the Credit Facility was amended to increase the
borrowing base to $14 million, and to eliminate the $300,000 per month automatic
reduction. In January 2002, the borrowing base was increased to $18 million. In
August 2002, the borrowing base was increased to $25 million. The borrowing base
is expected to be redetermined in the first half of 2003.

     The Credit Facility provides for certain restrictions, including but not
limited to, limitations on additional borrowings and issues of capital stock,
sales of oil and natural gas properties or other collateral, engaging in merger
or consolidation transactions. The Credit Facility also prohibits dividends and
certain distributions of cash or properties and certain liens. The Credit
Facility also contains certain financial covenants. The EBITDA to Interest
Expense Ratio requires that (a) our consolidated EBITDA, as defined in the
agreement, for the four fiscal quarters then ended to (b) our consolidated
interest expense for the four fiscal quarters then ended, to not be less than
3.5 to 1.0. The Working Capital ratio requires that the amount of our
consolidated current assets less our consolidated current liabilities, as
defined in the agreement, be at least $1.0 million. The Allowable Expenses ratio
requires that (a) the aggregate amount of our year-to-date consolidated general
and administrative expenses for the period from January 1 of such year through
the fiscal quarter then ended to (b) our year-to-date consolidated oil and gas
revenues, net of hedging activity, for the period from January 1 of such year
through the fiscal quarter then ended, to be less than 0.40 to 1.0.

     CONTRACTUAL CASH OBLIGATIONS

     The following table summarizes our contractual cash obligations as of
December 31, 2002 by payment due date:

<Table>
<Caption>
                                                  LESS THAN                            AFTER
                                         TOTAL     1 YEAR     1-3 YEARS   4-5 YEARS   5 YEARS
                                        -------   ---------   ---------   ---------   -------
                                                           (IN THOUSANDS)
<S>                                     <C>       <C>         <C>         <C>         <C>
Long-term debt........................  $20,500     $ --       $20,500      $ --      $   --
Operating leases......................    4,257      238         1,249       818       1,952
                                        -------     ----       -------      ----      ------
Total contractual cash obligations....  $24,757     $238       $21,749      $818      $1,952
                                        =======     ====       =======      ====      ======
</Table>

     RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

     In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets." SFAS No. 142 applies to all acquired intangible assets whether acquired
singly, as part of a group, or in a business combination. The statement
supersedes Accounting Principals Board, ("APB"), Opinion No. 17, "Intangible
Assets," and carries forward provisions in APB Opinion No. 17 related to
internally developed intangible assets. Under this statement, goodwill is no
longer to be amortized but is subject to annual impairment analysis. We adopted
this statement as of January 1, 2002, and we do not have any goodwill or
intangible assets recorded as of December 31, 2002.

     In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." The statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement of
tangible long-lived assets in the period in which it is incurred. When the
liability is initially recorded, the entity increases the carrying amount of the
related long-lived asset. Accretion of the liability is recognized each period,
and the capitalized cost is depreciated over the useful life of the related
asset. Upon settlement of the liability, an entity either settles the obligation
for its recorded amount or incurs a gain or loss upon settlement. The standard
is effective for fiscal years beginning after June 15, 2002, therefore we have
adopted SFAS No. 143 effective January 1, 2003 using a cumulative effect
approach to recognize transition amounts for asset retirement obligations, asset
retirement costs and accumulated depreciation. We currently do not include
dismantlement and abandonment costs in the depletion calculation as the vast
majority of our properties are onshore and the salvage value of the tangible
equipment typically offsets our dismantlement and abandonment costs. This
standard will require us to record a liability for the fair value of our
dismantlement

                                        38
<PAGE>

and abandonment costs, excluding salvage values. We expect that the adoption of
the statement will result in the recognition of additional liabilities related
to asset retirement obligations of approximately $1.1 million.

     In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 addresses the
accounting and reporting for the impairment or disposal of long-lived assets and
supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed of" and APB Opinion No. 30, "Reporting the
Results of Operations -- Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions." SFAS No. 144 establishes one accounting model for long-lived
assets to be disposed of by sale as well as resolves implementation issues
related to SFAS No. 121. The standard also expands the scope of discontinued
operations to include all components of an entity with operations that can be
distinguished from the rest of the entity and that will be eliminated from the
ongoing operations of the entity in a disposal transaction. The Company adopted
SFAS No. 144 effective January 1, 2002. Because we have elected the full-cost
method of accounting for oil and gas exploration and development activities, the
impairment provisions of SFAS No. 144 do not apply to our oil and gas assets,
which are instead subject to ceiling limitations. For our non-oil and gas
assets, the adoption of SFAS No. 144 did not have a material impact on the
consolidated financial statements.

     In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections". This statement rescinds SFAS No. 4, Reporting Gains and Losses
from Extinguishment of Debt, which required all gains and losses from
extinguishment of debt to be aggregated and, if material, classified as an
extraordinary item, net of income taxes. As a result, the criteria in APB No. 30
will now be used to classify those gains and losses. Any gain or loss on the
extinguishment of debt that was classified as an extraordinary item in prior
periods presented that does not meet the criteria in APB 30 for classification
as an extraordinary item shall be reclassified. The provisions of this Statement
are effective for fiscal years beginning after January 1, 2003. We do not expect
that adoption of this statement will have a material impact on our future
financial condition or results of operations.

     In June 2002, the FASB issued SFAS No. 146, "Accounting for Exit or
Disposal Activities". SFAS No. 146 addresses significant issues regarding the
recognition, measurement and reporting of disposal activities, including
restructuring activities that are currently covered in EITF Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Activity." The
provisions of SFAS No. 146 are effective for exit or disposal activities
initiated after December 31, 2002.

     In October 2002, the FASB issued SFAS No. 147, "Acquisitions of Certain
Financial Institutions -- an amendment of FASB Statements No. 72 and 144 and
FASB Interpretation No. 9". SFAS No. 147 provided interpretive guidance on the
application of the purchase method to acquisitions of financial institutions.
The provisions of SFAS No. 147 are effective for acquisitions occurring or after
October 1, 2002. We did not participate in any applicable activities as of and
for the period ending December 31, 2002.

     In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation -- Transition and Disclosure", an amendment of FASB Statement No.
123, "Accounting for Stock Based Compensation," ("SFAS No. 123"), which provides
alternative methods of transition for a voluntary change to the fair value based
method of accounting for stock-based employee compensation. In addition, this
Statement amends the disclosure requirements of Statement 123 to require
prominent disclosures in both annual and interim financial statements about the
method of accounting for stock-based employee compensation and the effect of the
method used on reported results. The provisions of SFAS No. 148 are effective
for fiscal years ending after December 15, 2002. As allowed by SFAS No. 123, we
have continued to apply APB Opinion No. 25 for purposes of determining net
income and to present the pro forma disclosure required by SFAS No. 123.

     During 2002, the FASB issued two interpretations: FIN 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" and FIN 46 "Consolidation of Variable
Interest Entities." There was no current impact of FIN 45 on our financial
position or results of operations. FIN 46 requires an entity to consolidate a
variable interest entity if it is the primary beneficiary of the variable
interest entity's activities. The primary beneficiary is the party that absorbs
a majority of the expected losses, receives a majority of the expected residual
returns, or both, from the
                                        39
<PAGE>

variable interest entity's activities. Upon its issuance, FIN 46 was applicable
immediately to variable interest entities created, or interests in variable
interest entities obtained, after January 31, 2003. For those variable interest
entities created, or interests in variable interest entities obtained, on or
before February 1, 2003, FIN 46 is required to be applied in the first fiscal
year or interim period beginning after June 15, 2003. FIN 46 may be applied
prospectively with a cumulative-effect adjustment as of the date it is first
applied, or by restating previously issued financial statements with a
cumulative-effect adjustment as of the beginning of the first year restated. FIN
46 also requires certain disclosures of an entity's relationship with variable
interest entities.

     We share interests with related parties in a variety of different
partnership and joint venture entities in order to share the rewards of
ownership in certain oil and natural gas royalties. We do not provide
supplemental financial support to these entities nor do we have voting rights.
In general, these entities are structured such that the sharing ratios in these
entities are consistent with the allocation of the entities' distributions of
cash from royalty revenues. We are continuing the process of examining all of
our ownership interests to determine the necessary disclosures and procedures
for complying with FIN 46. At this point, however, we do not anticipate that we
will be impacted by FIN 46 because there is no investment in or obligation to
share in future capital requirements of these entities.

     We do not expect the adoption of any of the above-mentioned standards to
have a material effect on our consolidated financial statements.

  Hedging Activities

     In March 2002, we purchased a floor on 18,000 MMbtus per day at $2.65 per
MMbtu for the period April 1, 2002 through June 30, 2002, at a cost of $163,800.
On August 22, 2002, we entered into a price swap on 5,000 MMbtus per day at
$3.59 per MMbtu for the period September 1, 2002 through December 31, 2002. On
August 23, 2002, we entered into a second price swap on an additional 5,000
MMbtus per day at $3.685 per MMbtu for the period September 1, 2002 through
December 31, 2002.

     In October 2002, we entered into a natural gas collar that covered 10,000
MMbtus per day for the period January 1, 2003 to December 31, 2003 at a floor of
$4.00 per MMbtu and a ceiling of $4.25 per MMbtu. At December 31, 2002, the
market value of outstanding hedges was approximately $(1.3) million and is
included in accrued liabilities.

     Due to the instability of oil and natural gas prices, we have entered into,
from time to time, price risk management transactions (e.g., swaps, collars and
floors) for a portion of our oil and natural gas production to achieve a more
predictable cash flow, as well as to reduce exposure from price fluctuations.
While the use of these arrangements limits our ability to benefit from increases
in the price of oil and natural gas, it also reduces our potential exposure to
adverse price movements. Our hedging arrangements, to the extent we enter into
any, apply to only a portion of our production and provide only partial price
protection against declines in oil and natural gas prices and limits our
potential gains from future increases in prices. Our Board of Directors sets all
of our hedging policies, including volumes, types of instruments and counter
parties, on a quarterly basis. These policies are implemented by management
through the execution of trades by the Chief Financial Officer after
consultation and concurrence by the President and Chairman of the Board. We
account for these transactions as hedging activities and, accordingly, realized
gains and losses are included in oil and natural gas revenue during the period
the hedged transactions occur. See ITEMS 1 AND 2. -- "BUSINESS AND
PROPERTIES -- MARKETING."

  Tax Matters

     At December 31, 2002, we have cumulative net operating loss carryforwards
("NOLs") for federal income tax purposes of approximately $27.4 million that
will begin to expire in 2012. We anticipate that all of these NOLs will be
utilized in connection with federal income taxes payable in the future. NOLs
assume that certain items, primarily intangible drilling costs have been written
off for tax purposes in the current year. However, we have not made a final
determination if an election will be made to capitalize all or part of these
items for tax purposes in the future.

                                        40
<PAGE>

ITEM 7A.  QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

     We are exposed to market risk from changes in interest rates and commodity
prices. We use a credit facility, which has a floating interest rate, to finance
a portion of our operations. We are not subject to fair value risk resulting
from changes in our floating interest rates. The use of floating rate debt
instruments provide a benefit due to downward interest rate movements but does
not limit us to exposure from future increases in interest rates. Based on the
year-end December 31, 2002 outstanding borrowings and a floating interest rate
of 3.88%, a 10% change in interest rate would result in an increase or decrease
of interest expense of approximately $75,900 on an annual basis.

     In the normal course of business we enter into hedging transactions,
including commodity price collars, swaps and floors to mitigate our exposure to
commodity price movements, but not for trading or speculative purposes. During
October 2002, due to the instability of prices and to achieve a more predictable
cash flow, we put in place a natural gas collar for a portion of our 2003
production. While the use of these arrangements may limit the benefit to us of
increases in the price of oil and natural gas, it also limits the downside risk
of adverse price movements. The natural gas collar covers 10,000 MMbtu per day
for the period January 1, 2003 to December 31, 2003 at a floor of $4.00 per
MMbtu and ceiling of $4.25 per MMbtu. At December 31, 2002, the fair value of
the outstanding hedge was approximately $(1.3) million. A 10% change in the gas
price per MMbtu, as long as the price is either above the ceiling or below the
floor price would cause the fair value total of the hedge to increase or
decrease by approximately $1.7 million.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     See the Consolidated Financial Statements and Supplementary information
listed in the accompanying Index to Consolidated Financial Statements and
Supplementary Information on page F-1 herein.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURES

     As noted in the Company's Current Report on Form 8-K filed on July 18,
2002, the Company dismissed its independent accountant, Arthur Andersen LLP, and
engaged KPMG LLP as its new independent accountant and auditor. The decision to
engage KPMG LLP and dismiss Arthur Andersen LLP was recommended by the Audit
Committee and approved by the Board of Directors.

     None of the reports of Arthur Andersen LLP on the financial statements of
the Company during their engagement contained an adverse opinion or was
qualified or modified as to uncertainty, audit scope or accounting principles.
Further, during the Company's fiscal year ended December 31, 2001 and for the
period from January 1, 2002 to July 18, 2002, there were no disagreements
between the Company and Arthur Andersen LLP on any matter of accounting
principles, or auditing scope or procedure, which disagreement, if not resolved
to the satisfaction of Arthur Andersen LLP, would have caused them to make
reference to the subject matter of the disagreements in connection with their
report on the financial statements for such years. There were no reportable
events (as defined in Regulation S-K, Item 304(a)(1)(v)) during the Company's
fiscal year ended December 31, 2001 and for the period from January 1, 2002 to
July 18, 2002. During the Company's fiscal year ended December 31, 2001 and for
the period from January 1, 2002 to July 18, 2002, the Company did not consult
with KPMG LLP regarding any of the matters or events set forth in Item
304(a)(2)(i) or (ii) of Regulation S-K.

     Subsequent to the appointment of KPMG and prior to the issuance of their
2002 report, the Company requested that KPMG perform a re-audit of the Company's
consolidated financial statements for the fiscal year ended December 31, 2001.
The re-audit was completed in March 2003, and KPMG's report dated March 14,
2003, which includes the 2001 period in its scope and was unmodified, is
included herein.

     As noted in the Company's Current Report on Form 8-K filed on October 10,
2001, on October 4, 2001, the Company dismissed its independent accountant,
Deloitte & Touche LLP, and engaged Arthur Andersen LLP as its new independent
accountant and auditor. The decision to engage Arthur Andersen, LLP and dismiss
Deloitte & Touche LLP was recommended by the Audit Committee and approved by the
Board of Directors.

     None of the reports of Deloitte & Touche LLP on the financial statements of
the Company during their engagement contained an adverse opinion or was
qualified or modified as to uncertainty, audit scope or
                                        41
<PAGE>

accounting principles. Further, during the Company's fiscal year ended December
31, 2000 and for the period from January 1, 2001 to October 4, 2001, there were
no disagreements between the Company and Deloitte & Touche LLP on any matter of
accounting principles, or auditing scope or procedure, which disagreement, if
not resolved to the satisfaction of Deloitte & Touche LLP, would have caused
them to make reference to the subject matter of the disagreements in connection
with their report on the financial statements for such years. There were no
reportable events (as defined in Regulation S-K, Item 304(a)(1)(v)) during the
Company's fiscal year ended December 31, 2000 and for the period from January 1,
2001 to October 4, 2001. During the Company's fiscal year ended December 31,
2000 and for the period from January 1, 2001 to October 4, 2001, the Company did
not consult with Arthur Andersen LLP or KPMG LLP regarding any of the matters or
events set forth in Item 304(a)(2)(i) or (ii) of Regulation S-K.

                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     The information regarding directors and executive officers required under
ITEM 10 is contained within the definitive Proxy Statement for the Company's
2003 Annual Meeting of Shareholders (the "Proxy Statement") under the headings
"Election of Directors" and "Compliance with Section 16(a) of the Exchange Act"
and is incorporated herein by reference. The Proxy Statement was filed pursuant
to Regulation 14A with the Securities and Exchange Commission not later than 120
days after December 31, 2002. Pursuant to Item 401(b) of Regulation S-K certain
of the information required by this item with respect to executive officers of
the Company is set forth in Part I of this report. In addition, we are providing
the following supplemental information.

     Thurmon M. Andress has served as a director of the Company since his
appointment to the Board in November 2002. For the past five years he has been
the president of Andress Oil & Gas Company, a private company located in
Houston, Texas, engaged in the business of oil and gas exploration and
development. He also serves as the managing director-Houston of Breitborn Energy
Company LLC, a private company headquartered in Los Angeles, California, engaged
in oil and gas production with operations primarily in California. Mr. Andress
has over 40 years of experience in the oil and gas industry. He is the chairman
of the Compensation Committee. He is 69 years old.

     John Sfondrini has served as a director of the Company since December 1996
and prior to that as director of the Company's corporate predecessors from 1986,
when he arranged for the capitalization of a predecessor partnership. For more
than five years, he has been self-employed as a consultant that assists his
clients in raising and investing private capital for growth-oriented companies
in multiple industry segments, including oil and gas. Mr. Sfondrini is a member
of the Compensation Committee of the Board. He is 54 years old.

ITEM 11.  EXECUTIVE COMPENSATION

     The information required by ITEM 11 is contained in the Proxy Statement
under the headings "Executive Compensation", "Summary Compensation Table",
"Options/SAR Grants", "Option/SAR Exercises and 2002 Year-End Option/SAR
Values", "401(k) Employee Savings Plan", "Employment Agreements and Change of
Control Agreements", "Compensation Committee Interlocks and Insider
Participation", "Performance Graph" and "Compensation Committee Report on
Executive Compensation" and is incorporated herein by reference.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
          RELATED STOCKHOLDER MATTERS

     The information required by ITEM 12 is contained in the Proxy Statement
under the headings "Security Ownership of Certain Beneficial Owners and
Management" and "Equity Compensation Plan Information" is incorporated herein by
reference.

                                        42
<PAGE>

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     The information required by ITEM 13 is contained in the Proxy Statement
under the heading "Certain Transactions" and is incorporated herein by
reference. In addition, we are providing the following supplemental information.

     The transactions disclosed under the caption "Certain Transactions" in the
Company's Proxy Statement were carried out on terms at least as favorable to the
Company as could have been obtained from unaffiliated third parties in arm's
length negotiations, however, because the transactions were with affiliates, it
is possible that the Company would have obtained different terms from a truly
unaffiliated third-party.

ITEM 14.  CONTROLS AND PROCEDURES

     Within the 90 days prior to the date of this report, the Company carried
out an evaluation, under the supervision and with the participation of the
Company's management, including the Chief Executive Officer and Chief Financial
and Accounting Officer, of the effectiveness of the design and operation of the
Company's disclosure controls and procedures pursuant to Exchange Act Rule
13a-14. Based on that evaluation, the Chief Executive Officer and the Chief
Financial and Accounting Officer concluded that the Company's disclosure
controls and procedures are effective in timely alerting them to material
information relating to the Company (including its consolidated subsidiaries)
required to be included in the Company's periodic filings with the Securities
and Exchange Commission. Subsequent to the date of their evaluation, there were
no significant changes in the Company's internal controls or in other factors
that could significantly affect the internal controls, including any corrective
actions with regard to significant deficiencies and material weaknesses.

                                    PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

     (a) Financial Statements and Schedules:

          1. Financial Statements:  See Index to the Consolidated Financial
     Statements and Supplementary Information immediately following the
     signature page of this report.

          2. Financial Statement Schedule:  See Index to the Consolidated
     Financial Statements and Supplementary Information immediately following
     the signature page of this report.

          3. Exhibits:  The following documents are filed as exhibits to this
     report.

<Table>
<C>            <S>   <C>
     2.1       --    Amended and Restated Combination Agreement by and among (i)
                     Edge Group II Limited Partnership, (ii) Gulfedge Limited
                     Partnership, (iii) Edge Group Partnership, (iv) Edge
                     Petroleum Corporation, (v) Edge Mergeco, Inc. and (vi) the
                     Company, dated as of January 13, 1997 (Incorporated by
                     reference from exhibit 2.1 to the Company's Registration
                     Statement on Form S-4 (Registration No. 333-17269)).
     3.1       --    Restated Certificate of Incorporation of the Company
                     (Incorporated by reference from exhibit 3.1 to the Company's
                     Registration Statement on Form S-1/A filed on February 5,
                     1997 (Registration No. 333-17267)).
     3.1A      --    Certificate of Amendment to the Restated Certificate of
                     Incorporation of the Company (Incorporated by reference from
                     exhibit 3.1 to the Company's Registration Statement on Form
                     S-1/A filed on February 5, 1997 (Registration No.
                     333-17267)).
     3.2       --    Bylaws of the Company (Incorporated by Reference from
                     exhibit 3.3 to the Company's Quarterly Report on Form 10-Q
                     for the quarterly period ended September 30, 1999).
     3.3       --    First Amendment to Bylaws of the Company on September 28,
                     1999 (Incorporated by Reference from exhibit 3.2 to the
                     Company's Quarterly Report on Form 10-Q for the quarterly
                     period ended September 30, 1999).
</Table>

                                        43
<PAGE>
<Table>
<C>            <S>   <C>
     4.1       --    Second Amended and Restated Credit Agreement dated October
                     6, 2000 by and between Edge Petroleum Corporation, Edge
                     Petroleum Exploration Company and Edge Petroleum Operating
                     Company, Inc. (collectively, the "Borrowers") and Union Bank
                     Of California, N.A., a national banking association, as
                     Agent for itself and as lender. (Incorporated by Reference
                     from exhibit 4.5 to the Company's Quarterly Report on Form
                     10-Q for the quarterly period ended September 31, 2000).
     4.2       --    Amendment No. 1 and Waiver dated as of November 11, 2001 by
                     and among the lenders party to the Second Amended and
                     Restated Credit Agreement dated October 6, 2000 ("Lenders"),
                     Union Bank of California, N.A., a national banking
                     association, as agent for such Lenders, Edge Petroleum
                     Corporation, Edge Petroleum Exploration Company, and Edge
                     Petroleum Operating Company, Inc. (collectively, the
                     "Borrowers"), as borrowers under the Second Amended and
                     Restated Credit Agreement. (Incorporated by Reference from
                     exhibit 4.2 to the Company's Annual Report on Form 10K for
                     the annual period ended December 31, 2001).
    +4.3       --    Amendment No. 2 dated as of May 29, 2002 by and among the
                     lenders party to the Second Amended and Restated Credit
                     Agreement dated October 6, 2000 ("Lenders"), Union Bank of
                     California, N.A., a national banking association, as agent
                     for such Lenders, Edge Petroleum Corporation, Edge Petroleum
                     Exploration Company, and Edge Petroleum Operating Company,
                     Inc. (collectively, the "Borrowers"), as borrowers under the
                     Second Amended and Restated Credit Agreement.
    +4.4       --    Amendment No. 3 dated as of August 8, 2002 by and among the
                     lenders party to the Second Amended and Restated Credit
                     Agreement dated October 6, 2000 ("Lenders"), Union Bank of
                     California, N.A., a national banking association, as agent
                     for such Lenders, Edge Petroleum Corporation, Edge Petroleum
                     Exploration Company, and Edge Petroleum Operating Company,
                     Inc. (collectively, the "Borrowers"), as borrowers under the
                     Second Amended and Restated Credit Agreement.
     4.5       --    Letter Agreement dated October 31, 2000 by and between Edge
                     Petroleum Corporation, Edge Petroleum Exploration Company
                     and Edge Petroleum Operating Company, Inc. (collectively,
                     the "Borrowers") and Union Bank Of California, N.A., a
                     national banking association, as Agent for itself and as
                     lender. (Incorporated by Reference from exhibit 4.6 to the
                     Company's Quarterly Report on Form 10-Q for the quarterly
                     period ended September 31, 2000).
     4.6       --    Letter Agreement dated March 23, 2001 by and between Edge
                     Petroleum Corporation, Edge Petroleum Exploration Company
                     and Edge Petroleum Operating Company, Inc. (collectively,
                     the "Borrowers") and Union Bank Of California, N.A., a
                     national banking association, as Agent for itself and as
                     lender. (Incorporated by Reference from exhibit 4.5 to the
                     Company's Annual Report on Form 10K for the annual period
                     ended December 31, 2000).
     4.7       --    Letter Agreement dated September 21, 2001 by and between
                     Edge Petroleum Corporation, Edge Petroleum Exploration
                     Company and Edge Petroleum Operating Company, Inc.
                     (collectively, the "Borrowers") and Union Bank Of
                     California, N.A., a national banking association, as Agent
                     for itself and as lender. (Incorporated by Reference from
                     exhibit 4.6 to the Company's Quarterly Report on Form 10Q
                     for the quarterly period ended September 30, 2001).
     4.8       --    Letter Agreement dated January 18, 2002 by and between Edge
                     Petroleum Corporation, Edge Petroleum Exploration Company
                     and Edge Petroleum Operating Company, Inc. (collectively,
                     the "Borrowers") and Union Bank Of California, N.A., a
                     national banking association, as Agent for itself and as
                     lender. (Incorporated by Reference from exhibit 4.6 to the
                     Company's Annual Report on Form 10K for the annual period
                     ended December 31, 2001).
     4.9       --    Letter Agreement dated August 9, 2002 by and between Edge
                     Petroleum Corporation, Edge Petroleum Exploration Company
                     and Edge Petroleum Operating Company, Inc. (collectively,
                     the "Borrowers") and Union Bank Of California, N.A., a
                     national banking association, as Agent for itself and as
                     lender. (Incorporated by Reference from exhibit 4.7 to the
                     Company's Quarterly Report on Form 10Q for the quarterly
                     period ended June 30, 2002).
     4.10      --    Common Stock Subscription Agreement dated as of April 30,
                     1999 between the Company and the purchasers named therein
                     (Incorporated by reference from exhibit 4.5 to the Company's
                     Quarterly Report on Form 10-Q/A for the quarter ended March
                     31, 1999).
     4.11      --    Warrant Agreement dated as of May 6, 1999 between the
                     Company and the Warrant holders named therein (Incorporated
                     by reference from exhibit 4.5 to the Company's Quarterly
                     Report on Form 10-Q/A for the quarter ended March 31, 1999).
</Table>

                                        44
<PAGE>
<Table>
<C>            <S>   <C>
     4.12      --    Form of Warrant for the purchase of the Common Stock
                     (Incorporated by reference from the Common Stock
                     Subscription Agreement from exhibit 4.5 to the Company's
                     Quarterly Report on Form 10-Q/A for the quarter ended March
                     31, 1999).
    10.1       --    Joint Venture Agreement between Edge Joint Venture II and
                     Essex Royalty Limited Partnership II, dated as of May 10,
                     1994 (Incorporated by reference from exhibit 10.2 to the
                     Company's Registration Statement on Form S-4 (Registration
                     No. 333-17269)).
    10.2       --    Joint Venture Agreement between Edge Joint Venture II and
                     Essex Royalty Limited Partnership, dated as of April 11,
                     1992 (Incorporated by reference from exhibit 10.3 to the
                     Company's Registration Statement on Form S-4 (Registration
                     No. 333-17269)).
   +10.3       --    Amendment dated August 21, 2000 to the Joint Venture
                     Agreement between Edge Joint Venture II and Essex Royalty
                     Limited Partnership II, dated as of May 10, 1994.
   +10.4       --    Amendment dated August 21, 2000 to the Joint Venture
                     Agreement between Edge Joint Venture II and Essex Royalty
                     Limited Partnership, dated as of April 11, 1992.
   +10.5       --    Letter Agreement between Edge Petroleum Corporation and
                     Essex Royalty Limited Partnership, dated as of July 30,
                     2002.
    10.6       --    Form of Indemnification Agreement between the Company and
                     each of its directors (Incorporated by reference from
                     exhibit 10.7 to the Company's Registration Statement on Form
                     S-4 (Registration No. 333-17269)).
    10.7       --    Stock Option Plan of Edge Petroleum Corporation, a Texas
                     corporation (Incorporated by reference from exhibit 10.13 to
                     the Company's Registration Statement on Form S-4
                     (Registration No. 333-17269)).
    10.8       --    Employment Agreement dated as of November 16, 1998, by and
                     between the Company and John W. Elias. (Incorporated by
                     reference from 10.12 to the Company's Annual Report on Form
                     10-K for the year ended December 31, 1998).
   +10.9       --    Incentive Plan of Edge Petroleum Corporation as Amended and
                     Restated Effective as of February 20, 2003.
    10.10      --    Edge Petroleum Corporation Incentive Plan "Standard
                     Non-Qualified Stock Option Agreement" by and between Edge
                     Petroleum Corporation and the Officers named therein.
                     (Incorporated by reference from exhibit 10.2 to the
                     Company's Quarterly Report on Form 10-Q for the quarterly
                     period ended September 30, 1999).
    10.11      --    Edge Petroleum Corporation Incentive Plan "Director
                     Non-Qualified Stock Option Agreement" by and between Edge
                     Petroleum Corporation and the Directors named therein.
                     (Incorporated by reference from exhibit 10.3 to the
                     Company's Quarterly Report on Form 10-Q for the quarterly
                     period ended September 30, 1999).
    10.12      --    Form of Employee Restricted Stock Award Agreement under the
                     Incentive Plan of Edge Petroleum Corporation (Incorporated
                     by Reference from exhibit 10.15 to the Company's Quarterly
                     Report on Form 10-Q/A for the quarterly period ended March
                     31, 1999).
    10.13      --    Edge Petroleum Corporation Amended and Restated Elias Stock
                     Incentive Plan. (Incorporated by reference from exhibit 4.5
                     to the Company's Registration Statement on Form S-8 filed
                     May 30, 2001 (Registration No. 333-61890)).
    10.14      --    Form of Edge Petroleum Corporation John W. Elias
                     Non-Qualified Stock Option Agreement (Incorporated by
                     reference from exhibit 4.6 to the Company's Registration
                     Statement on Form S-8 filed May 30, 2001 (Registration No.
                     333-61890)).
   +21.1       --    Subsidiaries of the Company.
   *23.1       --    Consent of KPMG LLP, independent auditors.
   *23.2       --    Consent of Deloitte & Touche LLP.
   *23.3       --    Consent of Ryder Scott Company.
   *31.1       --    Certification by John W. Elias, Chief Executive Officer,
                     pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the
                     Securities Exchange Act of 1934.
   *31.2       --    Certification by Michael G. Long , Chief Financial and
                     Accounting Officer, pursuant to Rule 13a-14(a) or Rule
                     15d-14(a) under the Securities Exchange Act of 1934.
</Table>

                                        45
<PAGE>
<Table>
<C>            <S>   <C>
   *32.1       --    Certification by John W. Elias, Chief Executive Officer,
                     pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
                     (Subsections (a) and (b) of Section 1350, Chapter 63 of
                     Title 18, United States Code).
   *32.2       --    Certification by Michael G. Long, Chief Financial and
                     Accounting Officer, pursuant to Section 906 of the
                     Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of
                     Section 1350, Chapter 63 of Title 18, United States Code).
   +99.1       --    Summary of Reserve Report of Ryder Scott Company Petroleum
                     Engineers as of December 31, 2002.
</Table>

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

* Filed herewith.

+ Previously filed.

     (b) Reports on Form 8-K:  The Company filed the following reports on Form
8-K during the quarter ended December 31, 2002:

     None.

                                        46
<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.

                                          EDGE PETROLEUM CORPORATION

                                                   /s/ JOHN W. ELIAS
                                          --------------------------------------
                                                      John W. Elias
                                           Chief Executive Officer and Chairman
                                                       of the Board

     Pursuant to the requirements 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.

<Table>
<S>     <C>                              <C>                                 <C>

          /s/ JOHN W. ELIAS                 Chief Executive Officer and      October 17, 2003
--------------------------------------   Chairman of the Board (Principal
            John W. Elias                       Executive Officer)


         /s/ MICHAEL G. LONG              Senior Vice President and Chief    October 17, 2003
--------------------------------------     Financial Officer (Principal
           Michael G. Long                    Financial and Principal
                                                Accounting Officer)


         /s/ THURMON ANDRESS                         Director                October 17, 2003
--------------------------------------
           Thurmon Andress


         /s/ VINCENT ANDREWS                         Director                October 17, 2003
--------------------------------------
           Vincent Andrews


        /s/ JOSEPH R. MUSOLINO                       Director                October 17, 2003
--------------------------------------
          Joseph R. Musolino


        /s/ STANLEY S. RAPHAEL                       Director                October 17, 2003
--------------------------------------
          Stanley S. Raphael


          /s/ JOHN SFONDRINI                         Director                October 17, 2003
--------------------------------------
            John Sfondrini


         /s/ ROBERT W. SHOWER                        Director                October 17, 2003
--------------------------------------
           Robert W. Shower


          /s/ DAVID F. WORK                          Director                October 17, 2003
--------------------------------------
            David F. Work
</Table>

                                        47
<PAGE>

                           EDGE PETROLEUM CORPORATION

    INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY INFORMATION

<Table>
<S>                                                           <C>
CONSOLIDATED FINANCIAL STATEMENTS
Audited Financial Statements:
Independent Auditors' Report -- 2002 and 2001...............   F-2
Independent Auditors' Report -- 2000........................   F-3
Consolidated Balance Sheets as of December 31, 2002 and
  2001......................................................   F-4
Consolidated Statements of Operations for the Years Ended
  December 31, 2002, 2001 and 2000..........................   F-5
Consolidated Statements of Cash Flows for the Years Ended
  December 31, 2002, 2001 and 2000..........................   F-6
Consolidated Statements of Stockholders' Equity for the
  Years Ended December 31, 2002, 2001 and 2000..............   F-7
Notes to Consolidated Financial Statements..................   F-8
Unaudited Information:
  Supplementary Information to Consolidated Financial
     Statements.............................................  F-26
CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
Independent Auditors' Report on Consolidated Financial
  Statement Schedule........................................  F-32
Schedule II -- Valuation and Qualifying Accounts and
  Reserves..................................................  F-33
</Table>

     All schedules for which provision is made in the applicable accounting
regulations of the Securities and Exchange Commission are not required under the
related instructions or are inapplicable and therefore have been omitted.

                                       F-1
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

The Board of Directors and Stockholders
Edge Petroleum Corporation:

     We have audited the accompanying consolidated balance sheets of Edge
Petroleum Corporation and subsidiaries as of December 31, 2002 and 2001, and the
related consolidated statements of operations, cash flows and stockholders'
equity for each of the years in the two-year period ended December 31, 2002.
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 Edge
Petroleum Corporation and subsidiaries as of December 31, 2002 and 2001, and the
results of their operations and their cash flows for each of the years in the
two-year period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America.

     As discussed in Note 2 to the consolidated financial statements, effective
January 1, 2001, the Company changed its method of accounting for derivative
instruments.

                                          KPMG LLP

Houston, Texas
March 14, 2003, except as to Note 14 which is as of August 28, 2003

                                       F-2
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

To the Stockholders and Board of Directors,
Edge Petroleum Corporation
Houston, Texas

     We have audited the accompanying consolidated statements of operations,
stockholders' equity, and cash flows of Edge Petroleum Corporation (a Delaware
Corporation) (the "Company") for the year ended December 31, 2000. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit.

     We conducted our audit 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 audit provides a
reasonable basis for our opinion.

     In our opinion, such consolidated financial statements present fairly, in
all materials respects, the Company's results of operations and cash flows for
the year ended December 31, 2000 in conformity with accounting principles
generally accepted in the United States of America.

                                               /s/ DELOITTE & TOUCHE LLP

March 19, 2001

                                       F-3
<PAGE>

                           EDGE PETROLEUM CORPORATION

                          CONSOLIDATED BALANCE SHEETS

<Table>
<Caption>
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 2002          2001
                                                              -----------   -----------
<S>                                                           <C>           <C>
                                        ASSETS
CURRENT ASSETS:
  Cash and cash equivalents.................................  $ 2,568,176   $   793,287
  Accounts receivable, trade, net of allowance of $525,248
     as of December 31, 2002 and 2001.......................    5,617,648     6,309,637
  Accounts receivable, joint interest owners, net of
     allowance of $82,000 and $163,000 as of December 31,
     2002 and 2001, respectively............................      403,446       517,001
  Current deferred tax asset................................      832,343       337,580
  Other current assets......................................      430,930       649,566
                                                              -----------   -----------
     Total current assets...................................    9,852,543     8,607,071
PROPERTY AND EQUIPMENT, Net -- full cost method of
  accounting for oil and natural gas properties.............   75,681,772    66,853,094
DEFERRED TAX ASSET..........................................       41,338       556,317
OTHER ASSETS................................................           --         7,788
                                                              -----------   -----------
TOTAL ASSETS................................................  $85,575,653   $76,024,270
                                                              ===========   ===========

                         LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
  Accounts payable, trade...................................  $ 1,533,972   $ 1,412,451
  Accrued liabilities.......................................    3,586,843     6,512,555
  Derivative financial instrument...........................    1,293,840            --
  Accrued interest payable..................................      127,698            --
                                                              -----------   -----------
     Total current liabilities..............................    6,542,353     7,925,006
LONG-TERM DEBT..............................................   20,500,000    10,000,000
                                                              -----------   -----------
     Total liabilities......................................   27,042,353    17,925,006
                                                              -----------   -----------
COMMITMENTS AND CONTINGENCIES (Note 6)
STOCKHOLDERS' EQUITY
  Preferred stock, $0.01 par value; 5,000,000 shares
     authorized; none issued and outstanding................           --            --
  Common stock, $0.01 par value; 25,000,000 shares
     authorized; 9,416,254 and 9,305,079 shares issued and
     outstanding at December 31, 2002 and 2001,
     respectively...........................................       94,163        93,051
  Additional paid-in capital................................   56,663,626    56,139,451
  Retained earnings.........................................    2,616,507     1,866,762
  Accumulated other comprehensive loss......................     (840,996)           --
                                                              -----------   -----------
     Total stockholders' equity.............................   58,533,300    58,099,264
                                                              -----------   -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY..................  $85,575,653   $76,024,270
                                                              ===========   ===========
</Table>

        See accompanying notes to the consolidated financial statements.

                                       F-4
<PAGE>

                           EDGE PETROLEUM CORPORATION

                     CONSOLIDATED STATEMENTS OF OPERATIONS

<Table>
<Caption>
                                                                YEAR ENDED DECEMBER 31,
                                                        ---------------------------------------
                                                           2002          2001          2000
                                                        -----------   -----------   -----------
<S>                                                     <C>           <C>           <C>
OIL AND NATURAL GAS REVENUE...........................  $20,911,294   $29,810,917   $23,774,416
OPERATING EXPENSES:
  Oil and natural gas operating expenses including
     production and ad valorem taxes..................    3,831,590     5,000,666     3,954,938
  Depletion, depreciation and amortization............   10,426,667     9,377,974     7,640,778
  Litigation settlement...............................           --     3,546,645            --
  General and administrative expenses:
     Deferred compensation expense -- repriced
       options........................................        3,385      (850,281)      899,548
     Deferred compensation expense -- restricted
       stock..........................................      399,249       353,371       127,946
     Other general and administrative.................    4,826,793     5,038,050     3,824,385
                                                        -----------   -----------   -----------
       Total operating expenses.......................   19,487,684    22,466,425    16,447,595
                                                        -----------   -----------   -----------
OPERATING INCOME......................................    1,423,610     7,344,492     7,326,821
OTHER INCOME AND (EXPENSE):
  Interest expense, net of amounts capitalized........     (227,759)     (214,619)     (171,783)
  Interest income.....................................       26,954       127,717        97,860
  Loss on sale of investment in Frontera..............           --            --      (354,733)
                                                        -----------   -----------   -----------
INCOME BEFORE INCOME TAXES............................    1,222,805     7,257,590     6,898,165
INCOME TAX BENEFIT (EXPENSE)..........................     (473,060)      818,897            --
                                                        -----------   -----------   -----------
NET INCOME............................................      749,745     8,076,487     6,898,165
OTHER COMPREHENSIVE INCOME:
  Cumulative effect transition adjustment.............           --    (1,137,221)           --
  Realization of hedging losses.......................           --       937,120            --
  Change in fair value of hedging instruments.........     (840,996)      200,101            --
                                                        -----------   -----------   -----------
     Other comprehensive income (loss)................     (840,996)           --            --
                                                        -----------   -----------   -----------
COMPREHENSIVE INCOME (LOSS)...........................  $   (91,251)  $ 8,076,487   $ 6,898,165
                                                        ===========   ===========   ===========
EARNINGS PER SHARE:
  Basic earnings per share............................  $      0.08   $      0.87   $      0.75
                                                        ===========   ===========   ===========
  Diluted earnings per share..........................  $      0.08   $      0.83   $      0.74
                                                        ===========   ===========   ===========
BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES
  OUTSTANDING.........................................    9,384,097     9,280,605     9,182,737
                                                        ===========   ===========   ===========
DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES
  OUTSTANDING.........................................    9,605,571     9,728,228     9,330,049
                                                        ===========   ===========   ===========
</Table>

        See accompanying notes to the consolidated financial statements.

                                       F-5
<PAGE>

                           EDGE PETROLEUM CORPORATION

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31,
                                                     ------------------------------------------
                                                         2002           2001           2000
                                                     ------------   ------------   ------------
<S>                                                  <C>            <C>            <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net income.......................................  $    749,745   $  8,076,487   $  6,898,165
  Adjustments to reconcile net income to net cash
     provided by operating activities:
     Depletion, depreciation and amortization......    10,426,667      9,377,974      7,640,778
     Amortization of deferred loan costs...........        84,479        101,398         24,720
     Deferred tax provision (benefit)..............       473,060       (818,897)            --
     Non-cash compensation expense.................       402,634       (496,910)     1,057,494
     Bad debt expense..............................            --        525,248             --
     Loss on sale of investment in Frontera........            --             --        354,733
  Changes in operating assets and liabilities:
     (Increase) decrease in accounts receivable,
       trade.......................................       691,989      2,742,218     (5,214,033)
     Decrease in accounts receivable, joint
       interest owners.............................       113,555         69,933        650,572
     (Increase) decrease in other assets...........       141,945       (519,322)        40,791
     Increase (decrease) in accounts payable,
       trade.......................................       121,521        135,011        (13,904)
     Increase (decrease) in accrued interest
       payable.....................................       127,698        (50,385)        34,016
     Increase (decrease) in accrued liabilities....    (2,925,712)     3,008,458     (1,827,745)
                                                     ------------   ------------   ------------
       Net cash provided by operating activities...    10,407,581     22,151,213      9,645,587
                                                     ------------   ------------   ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Purchase of prospects, property and equipment....   (19,609,639)   (28,988,659)   (10,717,839)
  Proceeds from the sale of prospects and oil and
     natural gas properties........................       354,294             --      1,810,659
  Proceeds from the sale of our investment in
     Frontera, net.................................            --             --      3,512,500
                                                     ------------   ------------   ------------
       Net cash used in investing activities.......   (19,255,345)   (28,988,659)    (5,394,680)
                                                     ------------   ------------   ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Borrowings from long-term debt...................    11,000,000     11,000,000      5,350,000
  Payments on long-term debt.......................      (500,000)    (4,000,000)    (9,150,000)
  Net proceeds from issuance of common stock.......       122,653        390,421             --
  Loan costs.......................................            --         (7,669)      (202,926)
                                                     ------------   ------------   ------------
       Net cash provided by (used in) financing
          activities...............................    10,622,653      7,382,752     (4,002,926)
                                                     ------------   ------------   ------------
NET INCREASE IN CASH AND CASH EQUIVALENTS..........     1,774,889        545,306        247,981
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR.......       793,287        247,981             --
                                                     ------------   ------------   ------------
CASH AND CASH EQUIVALENTS, END OF YEAR.............  $  2,568,176   $    793,287   $    247,981
                                                     ============   ============   ============
</Table>

        See accompanying notes to the consolidated financial statements.

                                       F-6
<PAGE>

                           EDGE PETROLEUM CORPORATION

                CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

<Table>
<Caption>
                                                                                   ACCUMULATED       UNEARNED
                                                     ADDITIONAL      RETAINED         OTHER       COMPENSATION --       TOTAL
                                                       PAID-IN       EARNINGS     COMPREHENSIVE     RESTRICTED      STOCKHOLDERS'
                                SHARES     AMOUNT      CAPITAL      (DEFICIT)     INCOME (LOSS)        STOCK           EQUITY
                               ---------   -------   -----------   ------------   -------------   ---------------   -------------
<S>                            <C>         <C>       <C>           <C>            <C>             <C>               <C>
BALANCE, DECEMBER 31, 1999...  9,182,023   $91,820   $55,223,901   $(13,107,890)   $        --       $(34,224)       $42,173,607
  Forfeitures of restricted
    common stock.............     (5,600)      (56)      (11,472)            --             --         11,528                 --
  Issuance of common stock...      9,648        97        29,903             --             --             --             30,000
  Deferred compensation
    expense -- restricted
    stock....................         --        --       105,250             --             --         22,696            127,946
  Deferred compensation
    expense -- repriced
    options..................         --        --       899,548             --             --             --            899,548
  Net income.................         --        --            --      6,898,165             --             --          6,898,165
                               ---------   -------   -----------   ------------    -----------       --------        -----------
BALANCE, DECEMBER 31, 2000...  9,186,071    91,861    56,247,130     (6,209,725)            --             --         50,129,266
  Issuance of common stock...    119,008     1,190       389,231             --             --             --            390,421
    Deferred compensation
      expense -- restricted
      stock..................         --        --       353,371             --             --             --            353,371
  Deferred compensation
    expense -- repriced
    options..................         --        --      (850,281)            --             --             --           (850,281)
  Transition adjustment......         --        --            --             --     (1,137,221)            --         (1,137,221)
  Realization of hedging
    loss.....................         --        --            --             --        937,120             --            937,120
  Change in valuation of
    hedging instruments......         --        --            --             --        200,101             --            200,101
  Net income.................         --        --            --      8,076,487             --             --          8,076,487
                               ---------   -------   -----------   ------------    -----------       --------        -----------
BALANCE, DECEMBER 31, 2001...  9,305,079    93,051    56,139,451      1,866,762             --             --         58,099,264
  Issuance of common stock...    111,175     1,112       121,541             --             --             --            122,653
    Deferred compensation
      expense -- restricted
      stock..................         --        --       399,249             --             --             --            399,249
  Deferred compensation
    expense -- repriced
    options..................         --        --         3,385             --             --             --              3,385
  Change in valuation of
    hedging instruments......         --        --            --             --       (840,996)            --           (840,996)
  Net income.................         --        --            --        749,745             --             --            749,745
                               ---------   -------   -----------   ------------    -----------       --------        -----------
BALANCE, DECEMBER 31, 2002...  9,416,254   $94,163   $56,663,626   $  2,616,507    $  (840,996)      $     --        $58,533,300
                               =========   =======   ===========   ============    ===========       ========        ===========
</Table>

        See accompanying notes to the consolidated financial statements.

                                       F-7
<PAGE>

                           EDGE PETROLEUM CORPORATION

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  ORGANIZATION AND NATURE OF OPERATIONS

     GENERAL -- Edge Petroleum Corporation (the "Company") was organized as a
Delaware corporation in August 1996 in connection with its initial public
offering and the related combination of certain entities that held interests in
Edge Joint Venture II (the "Joint Venture") and certain other oil and natural
gas properties; herein referred to as the "Combination". In a series of
combination transactions the Company issued an aggregate of 4,701,361 shares of
common stock and received in exchange 100% of the ownership interests in the
Joint Venture and certain other oil and natural gas properties. In March 1997,
and contemporaneously with the Combination, the Company completed the initial
public offering of 2,760,000 shares of its common stock (the "Offering")
generating proceeds of approximately $40 million, net of expenses.

     NATURE OF OPERATIONS -- The Company is an independent energy company
engaged in the exploration, development, acquisition and production of oil and
natural gas. The Company's resources and assets are managed and its results are
reported as one operating segment. The Company conducts its operations primarily
along the onshore United States Gulf Coast, with its primary emphasis in South
Texas and Louisiana. During 2001, the Company added a new focus area in the
northern Rocky Mountains that it expects to become a core area in 2003. The
Company currently controls interests in almost 160,000 gross acres held under
lease or option. In its exploration efforts the Company emphasizes an integrated
geologic interpretation method incorporating 3-D seismic technology and advanced
visualization and data analysis techniques utilizing state-of-the-art computer
hardware and software.

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     PRINCIPLES OF CONSOLIDATION -- The consolidated financial statements
include the accounts of all majority owned subsidiaries of the Company,
including Edge Petroleum Operating Company Inc., and Edge Petroleum Exploration
Company, which are 100% owned subsidiaries of the Company. All intercompany
transactions have been eliminated in consolidation.

     REVENUE RECOGNITION -- The Company recognizes oil and natural gas revenue
from its interests in producing wells as oil and natural gas is produced and
sold from those wells. Oil and natural gas sold by the Company is not
significantly different from the Company's share of production.

     OIL AND NATURAL GAS PROPERTIES -- Investments in oil and natural gas
properties are accounted for using the full cost method of accounting. All costs
associated with the exploration, development and acquisition of oil and natural
gas properties, including salaries, benefits and other internal costs directly
attributable to these activities, are capitalized within a cost center. The
Company's oil and natural gas properties are located within the United States of
America, which constitutes one cost center. The Company capitalized $1.5
million, $1.6 million, and $1.3 million of these internal costs in 2002, 2001
and 2000, respectively. Interest costs related to unproved properties are also
capitalized to unproved oil and gas properties. The Company capitalized
$623,400, $24,400, and $399,300 of these costs in 2002, 2001 and 2000,
respectively.

     Oil and natural gas properties are amortized using the unit-of-production
method using estimates of proved reserve quantities. Investments in unproved
properties are not amortized until proved reserves associated with the prospects
can be determined or until impairment occurs. Unevaluated properties are
evaluated periodically for impairment on a property-by-property basis. If the
results of an assessment indicate that an unproved property is impaired, the
amount of impairment is added to the proved oil and natural gas property costs
to be amortized. The amortizable base includes estimated future development
costs and, where significant, dismantlement, restoration and abandonment costs,
net of estimated salvage values. The vast majority of our properties are
onshore, and historically the salvage value of the tangible equipment offsets
our site restoration and dismantlement and abandonment costs. The depletion
rates per Mcfe for the years ended December 31, 2002, 2001 and 2000 were $1.40,
$1.22, and $1.11, respectively.

                                       F-8
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     Sales of proved and unproved properties are accounted for as adjustments of
capitalized costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves. Abandonments of oil and natural gas properties are accounted for as
adjustments of capitalized costs with no loss recognized.

     In addition, the capitalized costs of oil and natural gas properties are
subject to a "ceiling test," whereby to the extent that such capitalized costs
subject to amortization in the full cost pool (net of depletion, depreciation
and amortization and related deferred taxes) exceed the present value (using 10%
discount rate) of estimated future net after-tax cash flows from proved oil and
natural gas reserves, such excess costs are charged to operations. Once
incurred, an impairment of oil and natural gas properties is not reversible at a
later date. Impairment of oil and natural gas properties is assessed on a
quarterly basis in conjunction with the Company's quarterly filings with the
Securities and Exchange Commission. No adjustment related to the ceiling test
was required during the years ended December 31, 2002, 2001, or 2000.

     Depreciation of other office furniture and equipment and computer hardware
and software is provided using the straight-line method based on estimated
useful lives ranging from five to ten years.

     INCOME TAXES -- The Company accounts for income taxes under the provisions
of Statement of Financial Accounting Standards ("SFAS") No. 109 -- "Accounting
for Income Taxes," which provides for an asset and liability approach for
accounting for income taxes. Under this approach, deferred tax assets and
liabilities are recognized based on anticipated future tax consequences, using
currently enacted tax laws, attributable to differences between financial
statement carrying amounts of assets and liabilities and their respective tax
bases (see Note 7).

     STATEMENTS OF CASH FLOWS -- The consolidated statements of cash flows are
presented using the indirect method and consider all highly liquid investments
with original maturities of three months or less to be cash equivalents.

     INVESTMENT IN FRONTERA -- The Company sold its cost basis investment in
Frontera Resources Corporation in June 2000 for proceeds of $3.6 million and
paid related fees of $87,500 resulting in a loss on the sale of investment of
$354,733.

     STOCK-BASED COMPENSATION -- The Company accounts for stock compensation
plans under the intrinsic value method of Accounting Principles Board ("APB")
Opinion No. 25, "Accounting for Stock Issued to Employees." No compensation
expense is recognized for stock options that had an exercise price equal to the
market value of their underlying common stock on the date of grant. As allowed
by SFAS No. 123, "Accounting for Stock Based Compensation," the Company has
continued to apply APB Opinion No. 25 for purposes of determining net income. In
December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation -- Transition and Disclosure -- an amendment of FASB Statement No.
123" to provide alternative methods of transition for a voluntary change to the
fair value based method of accounting for stock-based employee compensation.
Additionally, the statement amends the disclosure requirements of SFAS No. 123
to require prominent disclosures in both annual and interim financial statements
about the method of accounting for stock-based compensation and the effect of
the method used on reported results.

     Had compensation expense for stock-based compensation been determined based
on the fair value at the date of grant, our net income, earnings available to
common stockholders and earnings per share would have

                                       F-9
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

been reduced and the stock-based compensation cost would have been increased to
the pro forma amounts indicated below:

<Table>
<Caption>
                                                         YEAR ENDED DECEMBER 31,
                                                    ----------------------------------
                                                      2002        2001         2000
                                                    --------   ----------   ----------
<S>                                                 <C>        <C>          <C>
Net income as reported............................  $749,745   $8,076,487   $6,898,165
  Add:
     Stock based employee compensation expense
       included in reported net income, net of
       related income tax.........................     2,075     (899,104)     899,548
  Deduct:
     Total stock based employee compensation
       expense determined under fair value based
       method for all awards, net of related
       income tax.................................  (261,927)    (594,129)    (584,316)
                                                    --------   ----------   ----------
Pro Forma Net Income..............................  $489,893   $6,583,254   $7,213,397
                                                    ========   ==========   ==========
Earnings Per Share
     Basic -- as reported.........................  $   0.08   $     0.87   $     0.75
     Basic -- pro forma...........................      0.05         0.71         0.79
     Diluted -- as reported.......................  $   0.08   $     0.83   $     0.74
     Diluted -- pro forma.........................      0.05         0.68         0.77
</Table>

     The weighted-average fair value of options granted during 2002, 2001 and
2000 was $4.19, $6.76 and $2.43. The fair value of each option grant is
estimated on the date of grant using the Black-Scholes option-pricing model with
the following weighted-average assumptions: expected stock price volatility of
77%, 80%, and 83% in 2002, 2001 and 2000, respectively; risk free interest of
3.82%, 5.42% and 5.12% in 2002, 2001 and 2000, respectively; average expected
option lives of eight years in 2002, 2001 and 2000, respectively; and a
forfeiture rate of 10% over the vesting period of such options.

     The Company is also subject to reporting requirements of Financial
Accounting Standards Board ("FASB") Interpretation No. (FIN) 44, Accounting for
Certain Transactions involving Stock Compensation that requires a non-cash
charge to deferred compensation expense if the market price of the Company's
common stock at the end of a reporting period is greater than the exercise price
of certain stock options. After the first such adjustment is made, each
subsequent period is adjusted upward or downward to the extent that the market
price exceeds the exercise price of the options. The charge is related to
non-qualified stock options granted to employees and directors in prior years
and re-priced in May 1999, as well as certain options newly issued in
conjunction with the repricing (see Note 9).

     EARNINGS PER SHARE -- The Company accounts for its earnings per share in
accordance with SFAS No. 128 -- "Earnings per Share," which establishes the
requirements for presenting earnings per share ("EPS"). SFAS No. 128 requires
the presentation of "basic" and "diluted" EPS on the face of the income
statement. Basic earnings per common share amounts are calculated using the
average number of common shares outstanding during each period. Diluted earnings
per share assumes the exercise of all stock options and warrants having exercise
prices less than the average market price of the common stock using the treasury
stock method (See Note 9).

     FINANCIAL INSTRUMENTS -- The Company's financial instruments consist of
cash, receivables, payables, long-term debt and oil and natural gas commodity
hedges. The carrying amount of cash, receivables and payables approximates fair
value because of the short-term nature of these items. The carrying amount of
long-term debt as of December 31, 2002 and 2001 approximates fair value because
the interest rates are variable and reflective of market rates. The fair value
of outstanding commodity sales price hedges was approximately $(1.3) million at
December 31, 2002. No hedges were outstanding at December 31, 2001.

                                       F-10
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     DERIVATIVES AND HEDGING ACTIVITIES -- Due to the instability of oil and
natural gas prices, the Company has entered into, from time to time, price risk
management transactions (e.g., swaps, collars and floors) for a portion of its
oil and natural gas production to achieve a more predictable cash flow, as well
as to reduce exposure from price fluctuations. While the use of these
arrangements limits the Company's ability to benefit from increases in the price
of oil and natural gas, it also reduces the Company's potential exposure to
adverse price movements. The Company's hedging arrangements, to the extent it
enters into any, apply to only a portion of its production and provide only
partial price protection against declines in oil and natural gas prices and
limits the Company's potential gains from future increases in prices. The
Company's Board of Directors sets all of the Company's hedging policies,
including volumes, types of instruments and counterparties, on a quarterly
basis. These policies are implemented by management through the execution of
trades by the Chief Financial Officer after consultation and concurrence by the
President and Chairman of the Board. The Company accounts for these transactions
as hedging activities and, accordingly, realized gains and losses are included
in oil and natural gas revenue during the period the hedged transactions occur
(see Note 5).

     The Company adopted SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities" effective January 1, 2001. The statement, as amended by
SFAS No. 137 and SFAS No. 138, requires that all derivatives be recognized as
either assets or liabilities and measured at fair value, and changes in the fair
value of derivatives be reported in current earnings, unless the derivative is
designated and effective as a hedge. If the intended use of the derivative is to
hedge the exposure to changes in the fair value of an asset, a liability or firm
commitment, then the changes in the fair value of the derivative instrument will
generally be offset in the income statement by the change in the item's fair
value. However, if the intended use of the derivative is to hedge the exposure
to variability in expected future cash flows then the changes in the fair value
of the derivative instrument will generally be reported in Other Comprehensive
Income (OCI). The gains and losses on the derivative instrument that are
reported in OCI will be reclassified to earnings in the period in which earnings
are impacted by the hedged item. The Company adopted SFAS No. 133 effective on
January 1, 2001, and recorded a transition adjustment of approximately $(1.1)
million in accumulated other comprehensive income to record the fair value of
the natural gas hedges that were outstanding at that date.

     Upon entering into a derivative contract, the Company designates the
derivative instruments as a hedge of the variability of cash flow to be received
(cash flow hedge). In accordance with SFAS No. 133, the Company formally
documents all relationships between hedging instruments and hedged items, as
well as its risk management objectives and strategy for undertaking various
hedge transactions. The Company also formally assesses, both at the hedge's
inception and on an ongoing basis, the effectiveness of transactions that
receive hedge accounting. All of the Company's derivative instruments at
December 31, 2002 and 2001 were designated and effective as cash flow hedges.

     When hedge accounting is discontinued because it is probable that a
forecasted transaction will not occur, the derivative will continue to be
carried on the balance sheet at its fair value and gains and losses that were
accumulated in other comprehensive income will be recognized in earnings
immediately. In all other situations in which hedge accounting is discontinued,
the derivative will be carried at fair value on the balance sheet with future
changes in its fair value recognized in earning prospectively.

     At December 31, 2002, all unrealized hedging gains and losses had been
recognized in accumulated other comprehensive income and the fair value of
outstanding hedges were reflected in the consolidated balance sheet as
derivative financial instruments.

     At December 31, 2002, we had recorded $0.9 million, net of related taxes of
$0.4 million, of cumulative hedging losses, which will be reclassified to
earnings within the next twelve months. The amounts ultimately reclassified to
earnings will vary due to changes in the fair value of the open derivative
instruments prior to settlement.

                                       F-11
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     Comprehensive Income -- The Company follows the provisions of SFAS No. 130,
"Reporting Comprehensive Income". SFAS No. 130 establishes standards for
reporting and presentation of comprehensive income and its components. SFAS No.
130 requires that all items that are required to be recognized under accounting
standards as components of comprehensive income be reported in a financial
statement that is displayed with the same prominence as other financial
statements. In accordance with the provisions of SFAS No. 130, the Company has
presented the components of comprehensive income below the total for net income
on the face of the Consolidated Statements of Operation. As of December 31,
2002, the Company had an unrealized loss from derivative hedging instruments of
$(840,996) that was deducted from net income to arrive at comprehensive loss of
$(91,251). For the years ended December 31, 2001 and 2000, there were no
adjustments to net income in deriving comprehensive income. The components of
other comprehensive income consist of unrealized and realized gain (loss) on
cash flow hedges, net.

     Use of Estimates -- The preparation of financial statements in conformity
with accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities as of the date of the financial statements and the reported amounts
of revenue and expenses during the reporting periods. Actual results could
differ from these estimates.

     Significant estimates include volumes of oil and gas reserves used in
calculating depreciation, depletion and amortization of proved oil and natural
gas properties, future net revenues and abandonment obligations used in
computing the ceiling test limitations, impairment of undeveloped properties,
future income taxes and related assets/liabilities, bad debts, derivatives,
contingencies and litigation. Oil and natural gas reserve estimates, which are
the basis for unit-of-production depletion and the ceiling test, have numerous
inherent uncertainties. The accuracy of any reserve estimate is a function of
the quality of available data and of engineering and geological interpretation
and judgment. Results of drilling, testing, and production subsequent to the
date of the estimate may justify revision of such estimate. Accordingly,
reserves estimates are often different from the quantities of oil and natural
gas that are ultimately recovered. In addition, reserve estimates are vulnerable
to changes in wellhead prices of crude oil and natural gas. Such prices have
been volatile in the past and can be expected to be volatile in the future.

     Concentration of Credit Risk -- Substantially all of the Company's accounts
receivable result from oil and natural gas sales or joint interest billings to
third parties in the oil and natural gas industry. This concentration of
customers and joint interest owners may impact the Company's overall credit risk
in that these entities may be similarly affected by changes in economic and
other conditions. Historically, the Company has not experienced significant
credit losses on such receivables; however, in 2001, the Company reserved
$525,248 related to non-payments from two purchasers of the Company's oil and
natural gas. No bad debt expense was recorded in 2002 or 2000. The Company
cannot ensure that similar such losses may not be realized in the future.

     Recently Issued Accounting Pronouncements -- In July 2001, the FASB issued
SFAS No. 143, "Accounting for Asset Retirement Obligations." The statement
requires entities to record the fair value of a liability for legal obligations
associated with the retirement of tangible long-lived assets in the period in
which it is incurred. When the liability is initially recorded, the entity
increases the carrying amount of the related long-lived asset. Accretion of the
liability is recognized each period, and the capitalized cost is depreciated
over the useful life of the related asset. Upon settlement of the liability, an
entity either settles the obligation for its recorded amount or incurs a gain or
loss upon settlement. The standard is effective for fiscal years beginning after
June 15, 2002, therefore the Company has adopted SFAS No. 143 effective January
1, 2003 using a cumulative effect approach to recognize transition amounts for
asset retirement obligations, asset retirement costs and accumulated
depreciation. The Company currently does not include dismantlement and
abandonment costs in the depletion calculation as the vast majority of our
properties are onshore and the salvage value of the tangible equipment typically
offsets our dismantlement and abandonment costs. This

                                       F-12
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

standard will require the Company to record a liability for the fair value of
our dismantlement and abandonment costs, excluding salvage values. The Company
expects that its adoption of the statement will result in additional liabilities
related to asset retirement obligations of approximately $1.1 million.

     In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 addresses the
accounting and reporting for the impairment or disposal of long-lived assets and
supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed of" and APB Opinion No. 30, "Reporting the
Results of Operations -- Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions." SFAS No. 144 establishes one accounting model for long-lived
assets to be disposed of by sale as well as resolves implementation issues
related to SFAS No. 121. The standard also expands the scope of discontinued
operations to include all components of an entity with operations that can be
distinguished from the rest of the entity and that will be eliminated from the
ongoing operations of the entity in a disposal transaction. The Company adopted
SFAS No. 144 effective January 1, 2002. Because the Company has elected the
full-cost method of accounting for oil and gas exploration and development
activities, the impairment provisions of SFAS No. 144 do not apply to the
Company's oil and gas assets, which are instead subject to ceiling limitations.
For the Company's non-oil and gas assets, the adoption of SFAS No. 144 did not
have a material impact on the consolidated financial statements.

     In April 2002, the FASB issued SFAS No. 145, "Recission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections". This statement rescinds SFAS No. 4, Reporting Gains and Losses
from Extinguishment of Debt, which required all gains and losses from
extinguishment of debt to be aggregated and, if material, classified as an
extraordinary item, net of income taxes. As a result, the criteria in APB No. 30
will now be used to classify those gains and losses. Any gain or loss on the
extinguishment of debt that was classified as an extraordinary item in prior
periods presented that does not meet the criteria in APB 30 for classification
as an extraordinary item shall be reclassified. The provisions of this Statement
are effective for fiscal years beginning after January 1, 2003. The Company does
not expect that adoption of this statement will have a material impact on the
Company's future financial condition or results of operations.

     In June 2002, the FASB issued SFAS No. 146, "Accounting for Exit or
Disposal Activities". SFAS No. 146 addresses significant issues regarding the
recognition, measurement and reporting of disposal activities, including
restructuring activities that are currently covered in EITF Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Activity." The
provisions of SFAS No. 146 are effective for exit or disposal activities
initiated after December 31, 2002.

     During 2002, the FASB issued two interpretations: FIN 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" and FIN 46 "Consolidation of Variable
Interest Entities." There was no current impact of FIN 45 on the Company's
financial position or results of operations. FIN 46 requires an entity to
consolidate a variable interest entity if it is the primary beneficiary of the
variable interest entity's activities. The primary beneficiary is the party that
absorbs a majority of the expected losses, receives a majority of the expected
residual returns, or both, from the variable interest entity's activities. Upon
its issuance, FIN 46 was applicable immediately to variable interest entities
created, or interests in variable interest entities obtained, after January 31,
2003. For those variable interest entities created, or interests in variable
interest entities obtained, on or before February 1, 2003, FIN 46 is required to
be applied in the first fiscal year or interim period beginning after June 15,
2003. FIN 46 may be applied prospectively with a cumulative-effect adjustment as
of the date it is first applied, or by restating previously issued financial
statements with a cumulative-effect adjustment as of the beginning of the first
year restated. FIN 46 also requires certain disclosures of an entity's
relationship with variable interest entities.

                                       F-13
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     The Company shares interests with related parties in a variety of different
partnership and joint venture entities in order to share the rewards of
ownership in certain oil and natural gas royalties. The Company does not provide
supplemental financial support to these entities nor does it have voting rights.
In general, these entities are structured such that the sharing ratios in these
entities are consistent with the allocation of the entities' distributions of
cash from royalty revenues. The Company is continuing the process of examining
all of its ownership interests to determine the necessary disclosures and
procedures for complying with FIN 46. At this point, however, the Company does
not anticipate that it will be impacted by FIN 46 because there is no investment
in or obligation to share in future capital requirements of these entities.

     The Company does not expect the adoption of any of the above-mentioned
standards to have a material effect on our consolidated financial statements.

     Reclassifications -- Certain prior year balances have been reclassified to
conform to the current year presentation.

3.  PROPERTY AND EQUIPMENT

     At December 31, 2002 and 2001, property and equipment consisted of the
following:

<Table>
<Caption>
                                                                  DECEMBER 31,
                                                           ---------------------------
                                                               2002           2001
                                                           ------------   ------------
<S>                                                        <C>            <C>
Developed oil and natural gas properties.................  $125,640,971   $101,303,892
Unevaluated oil and natural gas properties...............     7,901,315     13,105,817
Computer equipment and software..........................     4,067,405      4,035,598
Other office property and equipment......................     1,509,095      1,428,728
                                                           ------------   ------------
  Total property and equipment...........................   139,118,786    119,874,035
Accumulated depletion, depreciation and amortization.....   (63,437,014)   (53,020,941)
                                                           ------------   ------------
  Property and equipment, net............................  $ 75,681,772   $ 66,853,094
                                                           ============   ============
</Table>

     The Company uses the full-cost method of accounting for its oil and natural
gas properties. Unevaluated oil and natural gas properties are not subject to
amortization and consist of the cost of unevaluated leaseholds, cost of seismic
data, exploratory and developmental wells in progress, and secondary recovery
projects before the assignment of proved reserves. These costs are reviewed
periodically by management for impairment, with any costs impaired added to the
cost of oil and natural gas properties subject to amortization. Factors
considered by management in its impairment assessment include drilling results
by the Company and other operators, the terms of oil and natural gas leases not
held by production, production response to secondary recovery activities and
available funds for exploration and development.

                                       F-14
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     The following table summarizes the cost of the properties not subject to
amortization for the year the cost was incurred:

<Table>
<Caption>
                                                                    DECEMBER 31,
                                                              ------------------------
                                                                 2002         2001
                                                              ----------   -----------
<S>                                                           <C>          <C>
Year cost incurred:
  1997......................................................  $       --   $   213,216
  1998......................................................          --     3,152,756
  1999......................................................     193,060     1,264,424
  2000......................................................   1,126,667     2,441,465
  2001......................................................   3,069,611     6,033,956
  2002......................................................   3,511,977            --
                                                              ----------   -----------
     Total..................................................  $7,901,315   $13,105,817
                                                              ==========   ===========
</Table>

     Under the full-cost method, a sale of oil and natural gas properties,
whether or not being amortized currently, is accounted for as an adjustment of
capitalized costs, with no gain or loss recognized unless such adjustment would
significantly alter the relationship between capitalized costs and proved
reserves.

4.  LONG-TERM DEBT

     In October 2000, the Company entered into a new credit facility (the
"Credit Facility") with a bank. Borrowings under the Credit Facility bear
interest at a rate equal to prime plus 0.50% or LIBOR plus 2.75%. As of December
31, 2002, $20.5 million in borrowings were outstanding under the Credit
Facility, none of which is due in 2003. The Credit Facility matures October 6,
2004 and is secured by substantially all of the Company's assets.

     Originally the borrowing base under the Credit Facility was $5 million and
was subject to automatic reductions at a rate of $300,000 per month beginning
October 31, 2000. In March 2001, the Credit Facility was amended to increase the
borrowing base to $14 million, and to eliminate the $300,000 per month automatic
reduction. In January 2002, the borrowing base was increased to $18 million. In
August 2002, the borrowing base was increased to $25 million. The borrowing base
is expected to be redetermined in the first half of 2003.

     The Credit Facility provides for certain restrictions, including but not
limited to, limitations on additional borrowings and issues of capital stock,
sales of oil and natural gas properties or other collateral, and engaging in
merger or consolidation transactions. The Credit Facility also prohibits
dividends and certain distributions of cash or properties and certain liens. The
Credit Facility also contains certain financial covenants. The EBITDA to
Interest Expense Ratio requires that (a) consolidated EBITDA, as defined in the
agreement, of the Company for the four fiscal quarters then ended to (b) the
consolidated interest expense of the Company for the four fiscal quarters then
ended, not be less than 3.5 to 1.0. The Working Capital ratio requires that the
amount of the Company's consolidated current assets less its consolidated
current liabilities, as defined in the agreement, be at least $1.0 million. The
Allowable Expenses ratio requires that (a) the aggregate amount of the Company's
year to date consolidated general and administrative expenses for the period
from January 1 of such year through the fiscal quarter then ended to (b) the
Company's year to date consolidated oil and gas revenues, net of hedging
activity, for the period from January 1 of such year through the fiscal quarter
then ended, be less than 0.40 to 1.0. At December 31, 2002, the Company was in
compliance with the above-mentioned covenants.

                                       F-15
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

5.  HEDGING ACTIVITIES

     The impact on oil and natural gas revenue from hedging activities for the
three years ended December 31, 2002, 2001 and 2000 was as follows:

<Table>
<Caption>
                                                                              REALIZED HEDGING LOSSES
                         EFFECTIVE DATES                                  FOR THE YEAR ENDED DECEMBER 31,
HEDGE                  -------------------     PRICE PER       MMBTU    -----------------------------------
TYPE                     BEG.      ENDING        MMBTU        PER DAY     2002        2001         2000
-----                  --------   --------   --------------   -------   ---------   ---------   -----------
<S>                    <C>        <C>        <C>              <C>       <C>         <C>         <C>
NATURAL GAS:
Collar...............  02/01/00   02/29/00   $2.20 - $2.31     6,000    $      --   $      --   $   (70,470)
Collar...............  03/01/00   04/30/00   $2.20 - $2.50     6,000           --          --      (135,900)
Collar...............  05/01/00   09/30/00   $2.05 - $2.63     9,000           --          --    (1,342,320)
Collar...............  01/01/01   12/31/01   $4.50 - $6.70     4,000           --    (937,120)           --
Put Option...........  04/01/02   06/30/02   $        2.65    18,000     (163,800)         --            --
Swap.................  09/01/02   12/31/02   $        3.59     5,000     (110,550)         --            --
Swap.................  09/01/02   12/31/02   $        3.69     5,000      (52,600)         --            --
                                                                        ---------   ---------   -----------
     Total realized losses from gas hedging activities...............   $(326,950)  $(937,120)  $(1,548,690)
                                                                        =========   =========   ===========
</Table>

<Table>
<Caption>
                                                                               REALIZED HEDGING LOSSES
                         EFFECTIVE DATES                                   FOR THE YEAR ENDED DECEMBER 31,
HEDGE                  -------------------                      BARRELS   ---------------------------------
TYPE                     BEG.      ENDING    PRICE PER BARREL   PER DAY     2002        2001        2000
-----                  --------   --------   ----------------   -------   ---------   ---------   ---------
<S>                    <C>        <C>        <C>                <C>       <C>         <C>         <C>
OIL:
Swap.................  01/01/00   03/31/00        $25.60           150    $      --   $      --   $ (49,999)
                       04/01/00   06/30/00        $22.87           125           --          --     (65,478)
                       07/01/00   09/30/00        $21.47            60           --          --     (55,635)
                       10/01/00   12/31/00        $20.46            50           --          --     (52,342)
                                                                          ---------   ---------   ---------
     Total realized losses from oil hedging activities.................   $      --   $      --   $(223,454)
                                                                          =========   =========   =========
</Table>

     The Company's natural gas hedging activities are entered into on a per
MMbtu delivered price basis, Houston Ship Channel, with settlement for each
calendar month occurring five business days following the publishing of the
Inside F.E.R.C. Gas Marketing Report.

     In October 2002, the Company entered into a natural gas collar covering
10,000 MMbtu per day for the period January 1, 2003 to December 31, 2003 with a
floor of $4.00 per MMbtu and a ceiling of $4.25 per MMbtu. At December 31, 2002
and 2000, the fair value of outstanding hedges was approximately $(1.3) and
$(1.1) million, respectively. No hedges were outstanding at December 31, 2001.

6.  COMMITMENTS AND CONTINGENCIES

     From time to time the Company is a party to various legal proceedings
arising in the ordinary course of business. While the outcome of lawsuits cannot
be predicted with certainty, the Company is not currently a party to any
proceeding that it believes, if determined in a manner adverse to the Company,
could have a potential material adverse effect on its financial condition,
results of operations or cash flows.

     In October 2001, the Company was sued by certain mineral owners in its Mew
lease, upon which the Company and its partners drilled and completed the Mew No.
1 well in the Brandon Area, Duval County, Texas. The suit named the Company,
Santos USA and Mark Smith, an independent landman, as Defendants, and is filed
in the 229th Judicial District Court of Duval County, Texas. The suit sought a
declaratory judgment to set aside certain quitclaim deeds between the Mew
lessors that were intended to result in a

                                       F-16
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

partition of the mineral estate between the various members of the Mew family in
the land where the well is located and other lands. The pleadings alleged
failure of consideration, fraud, failure to consummate the partition, bad faith
trespass and conversion. As part of the leasing effort for the prospect, some
members of the Mew family had sought to partition their minerals under the
tracts where they owned the surface in full. The Mew heirs, from whom the
Company acquired leases, stood to lose a portion of their mineral interest if
the quitclaim deeds are set aside. Were this to happen, it could have the effect
of voiding the Company's leases as to an undivided one-third of the unit acreage
for the Mew well and the Mew lease. Plaintiffs sought unspecified actual and
exemplary damages against the Company and Santos arising out of the alleged
fraud committed by the Company and Mark Smith. They also sought damages from
Santos for the value of the oil and natural gas produced and saved from the Mew
well, or alternatively, for the value of the oil and natural gas produced less
the cost of drilling, completing and operating the well. The Company has a 12.5%
working interest in the well. To date, the Mew well has produced $5.7 million in
net revenue and has cost $3.6 million to drill, complete and operate. Estimated
gross proved reserves are 111.6 MBbls and 4.6 Bcf. In October 2002, the Company
reached a mediated settlement with all parties to the litigation whereby Edge
would make a one-time payment of $264,000 to the Mews, and in return, the Mews
released all claims except a potential drainage claim involving an offsetting
section, and agreed to grant a new oil and gas lease covering the disputed
mineral interest in the Mew well site tract. In addition, all claims as between
the working interest owners were released. The settlement has been consummated
and an order of dismal has been obtained from the Court.

     In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in the N. LaCopita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil filed a
counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. ExxonMobil sought
unspecified damages for the lost profits on the sale of the hydrocarbons from
this property, and for a determination of whether the Company and the other
working interest owners were in good faith or bad faith in trespassing on this
lease. If a determination of bad faith were made, the parties would not be able
to recover their costs of developing this property from the revenues therefrom.
While there is always a risk in the outcome of the litigation, the Company
believes there is no question that it acted in good faith and vigorously
defended its position. In February 2003, the Company, GMT and the other working
interest parties entered into a compromise and settlement agreement with Exxon
and Mrs. Neblett. Pursuant to the settlement, the Neblett wells have been
assigned to Exxon along with all operating responsibility, and all working
interest parties, including the Company, have been made whole for all out of
pocket costs incurred in drilling, completing, equipping and operating the
Neblett wells, including lease costs and royalty payments. The Company's share
of such reimbursed costs was $27,198. In addition, Mrs. Neblett will repay the
amount of the lease bonus and all royalty overpayments she received from GMT and
the other working interest parties, including the Company. Such payment is
secured by her future royalty interest payments in the wells, and other security
described in the settlement agreement, and is due in full on or before December
1, 2003. The Company's share of such lease bonus and royalty reimbursements is
$74,040. The parties have agreed to a dismissal of all claims in this case, and
a motion to dismiss with prejudice has been filed with the court.

     In a separate but related matter, certain nonparticipating royalty owners
represented by attorney John Mann in Laredo, have made demands on GMT as
operator, to pay certain royalty payments previously paid to Mrs. Neblett on
production from these wells, plus future royalty payments on such production. As
part of the

                                       F-17
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

settlement agreement, monies that were otherwise payable to Mrs. Neblett
attributable to her valid royalty interest under the ExxonMobil lease, subject
to execution of valid division orders and approval of their title, will be paid
to the Mann clients on account of their nonparticipating royalty interest. There
are other nonparticipating royalty owners similarly situated to the Mann clients
that have not made demands on GMT or the Company, whose claims, if any, will be
dealt with if and when they are made. There can be no guarantee that even when
the Mann clients are paid that they will not contest the amount or calculation
of the royalties in a separate lawsuit.

     In December 2001, the Company agreed to settle its litigation with BNP
Petroleum Corporation ("BNP"), Seiskin Interests, LTD, Pagenergy Company, LLC
and Gap Marketing Company, LLC. Pursuant to the settlement, the Company agreed
to pay $2.5 million and to release its claims to interest in an area known as
the Slick Prospect in Duval County, Texas. The parties to the settlement agreed
to the dismissal of all claims, both in the 229th Judicial District Court of
Duval County, Texas and in the 165th District Court in Harris County, Texas. The
parties also agreed to set aside the judgment of the 229th Judicial District
Court of Duval County, Texas against the Company and to a mutual release of all
claims. The Company recorded approximately $3.5 million paid to settle the
litigation including approximately $1.0 million in related legal costs in 2001
and reflected such total amount in the accompanying statement of operations as
litigation settlement.

     Additionally, the Company's operations are subject to numerous laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. Public interest in the
protection of the environment has increased dramatically in recent years. The
trend of more expansive and stricter environmental legislation and regulations
could continue. To the extent laws are enacted or other governmental action is
taken that restricts drilling or imposes environmental protection requirements
that result in increased costs to the oil and natural gas industry in general,
the business and prospects of the Company could be adversely affected.

     At December 31, 2002, the Company was obligated under noncancelable
operating leases. Following is a schedule of the remaining future minimum lease
payments under these leases:

<Table>
<S>                                                           <C>
2003........................................................  $  237,635
2004........................................................     419,814
2005........................................................     418,809
2006........................................................     410,644
Remainder...................................................   2,770,524
                                                              ----------
Total.......................................................  $4,257,426
                                                              ==========
</Table>

     Rent expense for the years ended December 31, 2002, 2001 and 2000 was
$566,663, $578,952, and $499,033, respectively.

                                       F-18
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

7.  INCOME TAXES

     Deferred income taxes reflect the tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts calculated for income tax purposes in accordance with
SFAS No. 109. Significant components of the Company's deferred tax liabilities
and assets as of December 31, 2002 and 2001 are as follows:

<Table>
<Caption>
                                                                   DECEMBER 31,
                                                             -------------------------
                                                                2002          2001
                                                             -----------   -----------
<S>                                                          <C>           <C>
Deferred tax liability:
  Book basis of oil and natural gas properties in excess of
     tax basis.............................................  $(9,636,351)  $(6,119,041)
Deferred tax asset:
  Expenses not currently deductible for tax purposes.......       26,250       221,550
  Net operating loss carryforwards.........................    9,602,689     6,353,358
  Deferred compensation....................................      112,362       122,143
  Federal alternative minimum tax credits..................       75,000        75,000
  Price risk management liability..........................      452,844            --
  Other....................................................      240,887       240,887
                                                             -----------   -----------
Total deferred tax asset...................................   10,510,032     7,012,938
                                                             -----------   -----------
Net deferred tax asset.....................................  $   873,681   $   893,897
                                                             ===========   ===========
</Table>

     The Company's provision (benefit) for income taxes consists of the
following:

<Table>
<Caption>
                                                            2002       2001      2000
                                                          --------   ---------   ----
<S>                                                       <C>        <C>         <C>
Current.................................................  $     --   $  75,000    $--
Deferred................................................   473,060    (893,897)   --
                                                          --------   ---------    --
  Total income tax benefit..............................  $473,060   $(818,897)   $--
                                                          ========   =========    ==
</Table>

     During 2001, the Company determined that it was more likely than not that
future taxable income would be sufficient to realize its recorded tax assets,
accordingly a valuation allowance totaling $3.2 million was reversed.

     The differences between the statutory federal income taxes calculated using
a federal tax rate of 35% and the Company's effective tax rate is summarized as
follows:

<Table>
<Caption>
                                                    2002        2001          2000
                                                  --------   -----------   -----------
<S>                                               <C>        <C>           <C>
Statutory federal income taxes..................  $427,982   $ 2,540,157   $ 2,414,358
  Non-deductible compensation expense...........    (7,545)     (175,802)    1,223,424
  Other expenses not deductible for tax
     purposes...................................    52,623        43,338        12,216
  Reduction in valuation allowance..............        --    (3,226,590)   (3,649,998)
                                                  --------   -----------   -----------
Income tax expense (benefit)....................  $473,060   $  (818,897)  $        --
                                                  ========   ===========   ===========
</Table>

     At December 31, 2002, the Company had cumulative net operating loss
carryforwards ("NOLs") for federal income tax purposes of approximately $27.4
million that will begin to expire in 2012. The Company anticipates that all of
these NOLs will be utilized in connection with federal income taxes payable in
the future. NOLs assume that certain items, primarily intangible drilling costs,
have been written off for tax purposes in the current year. However, the Company
has not made a final determination if an election will be made to capitalize all
or part of these items for tax purposes in the future.

                                       F-19
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

8.  EMPLOYEE BENEFIT PLANS

     Effective July 1, 1997, the Company established a defined-contribution
401(k) Savings & Profit Sharing Plan Trust (the "Plan") covering employees of
the Company who are age 21 or older. The Company's matching contributions to the
Plan are discretionary. For the years ended December 31, 2002, 2001 and 2000,
the Company contributed $83,223, $60,516, and $53,926, respectively, to the
Plan.

9.  EQUITY AND STOCK PLANS

     Private Offering -- On May 6, 1999, the Company completed a private
offering of 1,400,000 shares of common stock at a price of $5.40 per share. The
Company also issued warrants, which were purchased for $0.125 per warrant, to
acquire an additional 420,000 shares of common stock at $5.35 per share and are
exercisable through May 6, 2004. At the election of the Company, the warrants
may be called at a redemption price of $0.01 per warrant at any time after any
date at which the average daily per share closing bid price for the immediately
preceding 20 consecutive trading days exceeds $10.70. No warrants have been
exercised as of December 31, 2002.

     Stock Plan -- In conjunction with the Offering, the Company established the
Incentive Plan of Edge Petroleum Corporation (the "Incentive Plan"). The
Incentive Plan is discretionary and provides for the granting of awards,
including options for the purchase of the Company's common stock and for the
issuance of restricted and/or unrestricted common stock to directors, officers,
employees and independent contractors of the Company. The options and restricted
stock granted to date vest over periods of 2-10 years. An aggregate of 1,200,000
shares of common stock have been reserved for grants under the Incentive Plan,
of which 175,866 shares were available for future grants at December 31, 2002.
Shares of common stock awarded as restricted stock are subject to vesting
requirements and subject to risk of forfeiture until earned by continued
employment or service. During 2002, awards of 199,800 nonqualified stock options
were issued having an exercise price of $3.40 to $5.69 per share based on the
market value on the date of grant. Also during 2002, awards for 15,800 shares of
restricted stock were made having a value in the range of $3.40 to $5.21 per
share based on the market value on each award date. During 2001, awards for
100,800 shares of restricted stock were made having a value in the range of
$4.58 to $8.88 per share based on the market value on each award date. Shares of
common stock associated with these awards will be issued, subject to continued
employment, ratably over three years in accordance with the award's vesting
schedule, beginning on the first anniversary of the date of grant. Compensation
expense is amortized over the vesting period and offset to additional paid in
capital. Amortization of deferred compensation related to restricted stock
awards totaled $399,249, $353,371 and $127,946, respectively, for the years
ended December 31, 2002, 2001 and 2000.

     Effective May 21, 1999, the Company amended and restated the Incentive
Plan. In conjunction with those and other amendments of the Incentive Plan, the
Company exchanged, on a voluntary basis, 556,488 outstanding nonqualified stock
options of certain employees and Directors of the Company for 326,700 new common
stock options in replacement of those options. The exercise price of the
replacement options was $7.06 per share, which represents the fair market value
on the date of grant. The replaced options have a ten-year term with 50% of the
options vesting immediately on the date of grant with the remaining 50% vesting
on May 21, 2000. On May 21, 1999, in conjunction with the repricing, the Company
also issued 99,800 new ten-year common stock options to employees, which vested
100% on May 21, 2001. The exercise price of the new options was $7.06, which
represents the fair market value on the date of grant. On June 1, 1999, the
Company issued 21,000 ten-year common stock options to non-employee directors
with an exercise price of $7.28 per share, which represented their fair market
value at the date of grant, vesting 100% on June 1, 2001.

     Deferred compensation cost reported in accordance with FASB Interpretation
No. (FIN) 44, "Accounting for Certain Transactions involving Stock Compensation"
was a charge of $3,385 for the year ended December 31, 2002 compared to a credit
of $(850,281), or $(0.09) per share in 2001 and a charge of $899,548, or $0.10
per share, in 2000. FIN 44 requires, among other things, a non-cash charge to

                                       F-20
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

compensation expense if the market price of Edge's common stock at the end of a
reporting period is greater than the exercise price of certain options. FIN 44
could also result in a credit to compensation expense to the extent that the
trading price declines from the market price as of the end of the prior period,
but not below the exercise price of the options. The Company will adjust
deferred compensation expense upward or downward on a monthly basis, based on
the market price at the end of each such period as necessary to comply with FIN
44. We are required to report under this rule as a result of the replacement and
issuance of new options in conjunction with the repricing as discussed above.

     Effective January 8, 1999, as a component of his employment agreement with
the Company, John Elias, CEO and Chairman of the Board, was granted options
outside of the Incentive Plan for the purchase of 200,000 shares of common
stock. These options vest and become exercisable one-third upon issue, and one-
third upon each of January 1, 2000 and January 1, 2001. These amounts are
included within options granted for 1999. In January 2000, Mr. Elias was granted
additional options outside of the Incentive Plan for the purchase of 50,000
shares of common stock. These options vested and became 100% exercisable in
January 2002. In January 2001, Mr. Elias was granted additional options outside
the Incentive Plan for the purchase of another 50,000 shares of common stock.
These options vest and become 100% exercisable in January 2003. In January 2002,
Mr. Elias was granted additional options outside the Incentive Plan for the
purchase of another 50,000 shares of common stock that vest and become 100%
exercisable in January 2004. In April 2002, Mr. Elias was granted additional
options outside the Incentive Plan for the purchase of another 24,000 shares of
common stock. These options vest and become 100% exercisable in April 2004. In
April 2001, Mr. Elias was granted 14,000 shares of restricted stock outside the
Incentive Plan valued at $7.75 per share, the market value on the award date.
These shares are issued ratable over three years in accordance with the award's
vesting schedule, beginning on the first anniversary of the date of grant.
Compensation expense is amortized over the vesting period and offset to
additional paid in capital. The amortization of compensation expense related to
this award was included in the amounts discussed above. Below is a summary of
option and restricted stock grants to Mr. Elias:

<Table>
<Caption>
                                   SHARES      EXERCISE
DATE GRANTED                     OUTSTANDING    PRICE                DATE EXERCISABLE
------------                     -----------   --------              ----------------
<S>                              <C>           <C>        <C>
OPTIONS(1):
  5/21/1999....................    200,000      $4.22     One-third upon issue and one-third
                                                          upon each of January 1, 2000 and 2001
  1/3/2000.....................     50,000      $3.16     100% January 2002
  1/3/2001.....................     50,000      $8.88     100% January 2003
  1/3/2002.....................     50,000      $5.18     100% January 2004
  4/2/2002.....................     24,000      $5.59     100% April 2004
RESTRICTED STOCK(2) :
  4/2/2001.....................     14,000                Ratable over three years beginning on
                                                          the first anniversary of the date of
                                                          grant
</Table>

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

(1) Exercise price equals the fair market value on the date of grant.

(2) Value was $7.75 per share, the market value on the date of grant.

     In addition, as of the date of the Combination, Old Edge had in place a
stock incentive plan that was administered by non-employee members of the Board
of Directors of Old Edge. Prior to the Combination, two executives of the
Company each held outstanding options for the purchase of 2,193 shares of Old
Edge common stock granted under the Old Edge incentive plan. Upon completion of
the Combination, such options were converted into incentive stock options for
the purchase of an aggregate of 97,844 (48,922 for each of the two individuals)
shares of common stock of the Company (such number of shares of common stock as
would have existed if such options had been exercised immediately prior to the
Combination Transactions). After

                                       F-21
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

adjustment for the conversion, the option price per share of common stock for
each of the two 48,922 grants was approximately $4.09 and $2.04, respectively.
Options for the purchase of 48,922 shares of common stock were exercised during
1997. The remaining options to purchase 48,922 shares of common stock were
exercised during 2001.

     A summary of the status of the Company's stock options and changes as of
and for each of the three years ended December 31, 2002 is presented below:

<Table>
<Caption>
                                            2002                   2001                   2000
                                          WEIGHTED               WEIGHTED               WEIGHTED
                                          AVERAGE                AVERAGE                AVERAGE
                                          EXERCISE               EXERCISE               EXERCISE
                               SHARES      PRICE      SHARES      PRICE      SHARES      PRICE
                             ----------   --------   ---------   --------   ---------   --------
<S>                          <C>          <C>        <C>         <C>        <C>         <C>
Outstanding, January 1.....     866,200    $5.62       993,517    $ 6.76      818,567    $7.74
Granted....................     273,800    $5.46        92,200    $ 8.49      284,100    $3.36
Purchased..................          --               (133,645)   $16.50           --
Forfeited..................     (24,650)   $5.70       (10,000)   $ 3.66     (109,150)   $5.20
Exercised..................     (17,300)   $3.01       (75,872)   $ 5.15           --
                             ----------              ---------              ---------
Outstanding, December 31...   1,098,050    $5.62       866,200    $ 5.62      993,517    $6.76
                             ==========              =========              =========
Exercisable, December
  31,......................     752,050    $5.34       574,200    $ 6.07      626,651    $8.24
                             ==========              =========              =========
Weighted average fair value
  of options granted during
  the period...............  $     4.19              $    6.76              $    2.43
                             ==========              =========              =========
</Table>

     The Company purchased 133,645 options from a former employee at a cost of
$100,000 that was included in general and administrative costs for the year
ended December 31, 2001.

     A summary of the Company's stock options categorized by class of grant at
December 31, 2002 is presented below:

<Table>
<Caption>
ALL OPTIONS
-------------------------------------------------------------           OPTIONS EXERCISABLE
                                        WEIGHTED                ------------------------------------
                                         AVERAGE     WEIGHTED                               WEIGHTED
                                        REMAINING    AVERAGE     RANGE OF                   AVERAGE
                           SHARES      CONTRACTUAL   EXERCISE    EXERCISE       SHARES      EXERCISE
RANGE OF EXERCISE PRICE  OUTSTANDING      LIFE        PRICE        PRICE      OUTSTANDING    PRICE
-----------------------  -----------   -----------   --------   -----------   -----------   --------
<S>                      <C>           <C>           <C>        <C>           <C>           <C>
$2.11-$6.44...........     185,700         7.20       $ 3.08    $2.11-$6.44     182,300      $ 3.06
$4.22.................     200,000         6.02       $ 4.22    $      4.22     200,000      $ 4.22
$8.56-$8.88...........      66,000         8.02       $ 8.87             --          --          --
$7.06-$7.58...........     384,650         6.39       $ 7.09    $7.06-$7.28     369,650      $ 7.07
$5.18-$5.69...........     261,600         9.21       $ 5.50
$13.50................         100         4.98       $13.50    $     13.50         100      $13.50
</Table>

                                       F-22
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     Computation of Earnings per Share -- The following is presented as a
reconciliation of the numerators and denominators of basic and diluted earnings
per share computations, in accordance with SFAS No. 128.

<Table>
<Caption>
                                                        YEAR ENDED DECEMBER 31, 2002
                                                   ---------------------------------------
                                                     INCOME         SHARES       PER SHARE
                                                   (NUMERATOR)   (DENOMINATOR)    AMOUNT
                                                   -----------   -------------   ---------
<S>                                                <C>           <C>             <C>
BASIC EPS
  Income available to common stockholders........   $749,745       9,384,097      $ 0.08
EFFECT OF DILUTIVE SECURITIES
  Common stock options...........................         --          85,633       (0.00)
  Restricted stock...............................         --         135,841       (0.00)
                                                    --------       ---------      ------
DILUTED EPS
  Income available to common stockholders........   $749,745       9,605,571      $ 0.08
                                                    ========       =========      ======
</Table>

<Table>
<Caption>
                                                        YEAR ENDED DECEMBER 31, 2001
                                                   ---------------------------------------
                                                     INCOME         SHARES       PER SHARE
                                                   (NUMERATOR)   (DENOMINATOR)    AMOUNT
                                                   -----------   -------------   ---------
<S>                                                <C>           <C>             <C>
BASIC EPS
  Income available to common stockholders........  $8,076,487      9,280,605      $ 0.87
EFFECT OF DILUTIVE SECURITIES
  Common stock options...........................          --        185,177       (0.02)
  Restricted stock...............................          --        178,238       (0.02)
  Warrants.......................................          --         84,208          --
                                                   ----------      ---------      ------
DILUTED EPS
  Income available to common stockholders........  $8,076,487      9,728,228      $ 0.83
                                                   ==========      =========      ======
</Table>

<Table>
<Caption>
                                                        YEAR ENDED DECEMBER 31, 2000
                                                   ---------------------------------------
                                                     INCOME         SHARES       PER SHARE
                                                   (NUMERATOR)   (DENOMINATOR)    AMOUNT
                                                   -----------   -------------   ---------
<S>                                                <C>           <C>             <C>
BASIC EPS
  Income available to common stockholders........  $6,898,165      9,182,737      $ 0.75
EFFECT OF DILUTIVE SECURITIES
  Common stock options...........................          --         27,130          --
  Restricted stock...............................          --        120,182       (0.01)
                                                   ----------      ---------      ------
DILUTED EPS
  Income available to common stockholders........  $6,898,165      9,330,049      $ 0.74
                                                   ==========      =========      ======
</Table>

10.  RELATED PARTY TRANSACTIONS

     Essex Royalty Joint Ventures -- A company wholly owned by Mr. Sfondrini, a
director of the Company, is the general partner of each of Essex Royalty Limited
Partnership ("Essex I L.P.") and Essex Royalty Limited Partnership II ("Essex II
L.P."). In April 1992, a predecessor partnership of the Company and Essex I L.P.
entered into a Joint Venture Agreement (the "Essex I Joint Venture") with
respect to the purchase of certain royalty and nonoperating interests in oil and
natural gas properties. In May 1994, the Company's predecessor partnership and
Essex II L.P. entered into a Joint Venture Agreement (the "Essex II Joint
Venture") similar in nature to the Essex I Joint Venture. The Company previously
served as manager of the

                                       F-23
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Essex I and II Joint Ventures. Effective January 1, 2001, Mr. Sfondrini and a
company wholly owned by Mr. Sfondrini assumed the Company's duties as manager of
the Essex I and II Joint Ventures.

     The Essex I Joint Venture terminated in April 1997. Under the terms of the
Essex I Joint Venture Agreement, Essex I L.P. made capital contributions
aggregating $3 million and the Company and its predecessor made no capital
contributions. The Essex I Joint Venture Agreement provides that quarterly
distributions of cash be made, in accordance with specified sharing ratios, in
an amount, subject to certain adjustments, not less than that equal to revenues
received from royalties less the management fee paid to the managing venturer
and the expenses of the Essex I Joint Venture. Initially, Essex I L.P. receives
100% of all cash distributions pursuant to the sharing ratios until a certain
payout amount has been recouped as defined in the Essex I Joint Venture
Agreement, as amended, at which time the sharing ratios shift to 40% for the
Company and 60% for Essex I L.P. Pursuant to an amendment of the Essex I Joint
Venture in August 2000, the time at which the sharing ratio shifts, or payout
under the joint venture agreement for Essex I Joint Venture would occur, was
extended until the limited partners of Essex I L.P. had recovered 100% of their
initial capital investment in Essex I L.P. and certain additional amounts had
been distributed by Essex I Joint Venture to Essex I L.P. As a result of the
August 2000 amendment, the sharing ratio shift for Essex I Joint Venture occurs
when the aggregate amount of cash and property interests (valued as determined
by the Joint Venture agreement) actually distributed to the Essex I L.P. during
2001 and subsequent years equals $510,159. The sharing ratio shift, or payout,
for Essex I Joint Venture occurred in 2001, and the Company became entitled to
receive from Essex I Joint Venture 40% of the net royalty distributions.

     In July 2002, Essex I L.P. and the Company modified the August 2000
amendment to the Essex I Joint Venture Agreement. The modification provided,
among other things, that the managing venturer of Essex I Joint Venture would be
entitled to a management fee of 3% per month of the gross distributions from
Essex I Joint Venture. In addition, in consideration of the granting of mutual
releases between Essex I Joint Venture, Essex I L.P., the new managers of the
venture and the Company of any claims, losses and demands arising out of the
Company's prior management of the Essex I Joint Venture, the Company agreed to
waive the amount owed to it as of March 31, 2002 on account of its 40%
after-payout interest in Essex I Joint Venture, which amount the Company
calculated to be $111,480. Finally, the parties agreed that Edge Group
Partnership, a general partnership, the partners of which are three limited
partnerships, the general partner of each of which is a company wholly owned by
Mr. Sfondrini, would be entitled to a de-minimus (less than .4%) portion of the
after-payout distributions from Essex I Joint Venture. In accordance with the
terms of the 2002 amendment, commencing effective in April 2002, Essex I Joint
Venture began making cash payments to the Company on account of its 40%
after-payout interest in the royalty properties. During 2002, the Essex I Joint
Venture distributed $202,685, $632 and $59,146 in net royalty distributions to
Essex I L.P., Edge Group Partnership and the Company, respectively.

     The Essex II Joint Venture terminated in December 31, 1998. Essex II L.P.
made capital contributions aggregating approximately $4.6 million and the
Company and its predecessor made no capital contributions. Initially, Essex II
L.P. receives 100% of all cash distributions pursuant to the sharing ratios
until a certain payout amount has been recouped as defined in the Essex II Joint
Venture Agreement, as amended, at which time the sharing ratios shift to 25% for
the Company and 75% for Essex II L.P. Provisions with respect to mandatory
quarterly distributions are similar to those described for the Essex I Joint
Venture. Pursuant to an amendment of the Essex II Joint Venture in August 2000,
the time at which the sharing ratio shifts, or payout under the joint venture
agreement for Essex II Joint Venture would occur, was extended until the limited
partners of Essex II L.P. had recovered 100% of their initial capital investment
in Essex II L.P. As a result of the July 2000 amendment, the sharing ratio shift
for Essex II Joint Venture occurs when the aggregate amount of cash and property
interests (valued as determined by the joint venture agreement) actually
distributed to the Essex II L.P. during 2001 and subsequent years equals
$3,324,587. During 2001 and 2002, the aggregate amount of cash distributed to
Essex II L.P. was $1,325,092 and $436,899, respectively, leaving

                                       F-24
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

an amount of $1,562,596 remaining to be recovered by Essex II L.P. before payout
and a sharing ratio shift occurs for Essex II Joint Venture.

     During 2002, Mr. Sfondrini accrued management and administration fees
(including expenses he is entitled to be reimbursed for) in the amount of
$29,817 for managing the Essex I and II Joint Ventures, $27,825 of which was
paid to third parties who performed management, administration and tax services
for Mr. Sfondrini on behalf of the Joint Ventures.

     Affiliates' Ownership in Prospects -- A company wholly owned by Mr.
Sfondrini and another corporation of which Mr. Andrews (a director of the
Company) is an officer, are the general partners of Jovin, L.P., a limited
partnership that previously has invested, on the same basis as outside parties,
in certain wells in prospects generated by the Company. As a result of such
investments, Jovin, L.P. is entitled to an approximate 2% working interest in
the Company's Phoenix Prospect in Live Oak County, Texas. Jovin, L.P. made
payments to the Company during 2002 on account of Jovin, L.P.'s pro rata share
of certain land and lease operating expenses for this prospect in the aggregate
amount of $100,094.

     Edge Group Partnership, Edge Holding Company, L.P., a limited partnership
of which Mr. Sfondrini and a corporation wholly owned by him are the general
partners, Andex Energy Corporation and Texedge Energy Corporation, corporations
of which Mr. Andrews is an officer and members of his immediate family hold
ownership interests, Mr. Raphael (a director of the Company), Jovin, L.P. and
Essex II Joint Venture, own certain working interests in the Company's Nita and
Austin Prospects and certain other wells and prospects operated by the Company.
These working interests aggregate 7.19% in the Austin Prospect, 6.27% in the
Nita Prospect and are negligible in other wells and prospects. These working
interests bear their share of lease operating costs and royalty burdens on the
same basis as the Company. In addition, Bamaedge, L.P., a limited partnership of
which Andex Energy Corporation is the general partner, and Mr. Raphael also hold
overriding royalty interests with respect to the Company's working interest in
certain wells and prospects. Neither Mr. Raphael nor Bamaedge L.P. has an
overriding interest in excess of .075% in any one well or prospect. Essex I and
II Joint Ventures own royalty and overriding royalty interests in various wells
operated by the Company. The combined royalty and overriding royalty interests
of the Essex I and Essex II Joint Ventures do not exceed 6.2% in any one well or
prospect. The gross amounts paid or accrued to these persons by the Company in
2002 (including net revenue, royalty and overriding royalty interests) and the
amounts these same persons paid to the Company for their respective share of
lease operating expenses is set forth in the following table:

<Table>
<Caption>
                                                              TOTAL AMOUNTS       LEASE
                                                               PAID BY THE      OPERATING
                                                                COMPANY TO      EXPENSES
                                                                OWNERS IN      PAID TO THE
                                                              2002 INCLUDING     COMPANY
                                                                OVERRIDING      BY OWNERS
OWNER                                                           ROYALTY(1)       IN 2002
-----                                                         --------------   -----------
<S>                                                           <C>              <C>
Andex Corporation/Texedge Corporation.......................     $  3,370       $    391
Bamaedge, L.P...............................................        1,247             --
Edge Group Partnership......................................      316,512         80,716
Edge Holding Company, L.P...................................       59,491         15,460
Essex I Joint Venture.......................................       15,043          1,658
Essex II Joint Venture......................................       87,066         15,507
Jovin, L.P..................................................           --        100,094
Stanley Raphael.............................................        3,455            750
                                                                 --------       --------
  Total.....................................................     $486,184       $214,576
                                                                 ========       ========
</Table>

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

(1) In the case of Essex I and II Joint Ventures, amount includes royalty income
    in addition to working interest and overriding royalty income.

                                       F-25
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

11.  SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES

     A summary of non-cash investing and financing activities for the years
ended December 31, 2002, 2001 and 2000 is presented below:

<Table>
<Caption>
                                                               NUMBER       FAIR
                                                              OF SHARES    MARKET
DESCRIPTION                                                    ISSUED      VALUE
-----------                                                   ---------   --------
<S>                                                           <C>         <C>
2002:
Shares issued to satisfy restricted stock grants............   76,337     $409,777
Shares issued to fund the Company's matching contribution
  under the Company's 401 (k) plan..........................   17,538     $ 70,513
2001:
Shares issued to satisfy restricted stock grant.............   43,136     $131,134
2000:
Shares issued to satisfy restricted stock grant.............    9,648     $ 30,000
Forfeitures of restricted stock.............................    5,600     $ 11,528
</Table>

     Supplemental Disclosure of Cash Flow Information

<Table>
<Caption>
                                                         FOR THE YEAR ENDED DECEMBER 31,
                                                         -------------------------------
                                                           2002       2001       2000
                                                         --------   --------   ---------
<S>                                                      <C>        <C>        <C>
Cash paid during the period for:
  Interest, net of amounts capitalized.................  $15,582    $54,081    $133,093
  Federal alternative minimum tax payments.............       --    322,000          --
</Table>

12.  SUPPLEMENTAL FINANCIAL QUARTERLY RESULTS (UNAUDITED):

<Table>
<Caption>
                                   FOURTH QUARTER   THIRD QUARTER   SECOND QUARTER   FIRST QUARTER
                                   --------------   -------------   --------------   -------------
                                              (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S>                                <C>              <C>             <C>              <C>
2002
  Oil and natural gas revenue....     $ 4,407          $5,164           $6,432          $ 4,908
  Operating expenses.............       4,238           4,820            5,219            5,210
  Operating income (loss)........         169             344            1,213             (302)
  Other expense, net.............         (76)            (81)             (22)             (22)
  Income tax benefit (expense)...         (56)           (107)            (427)             117
  Net income (loss)..............     $    37          $  156           $  764          $  (207)
  Basic earnings (loss) per
     share.......................     $  0.00          $ 0.02           $ 0.08          $ (0.02)
  Diluted earnings (loss) per
     share.......................     $  0.00          $ 0.02           $ 0.08          $ (0.02)
2001
  Oil and natural gas revenue....     $ 4,062          $6,181           $8,045          $11,523
  Operating expenses.............       7,386           5,831            5,210            4,040
  Operating income (loss)........      (3,324)            350            2,835            7,483
  Other expense, net.............         (53)             (4)             (19)             (11)
  Income tax benefit (expense)...       1,478             123              240           (1,022)
  Net income (loss)..............     $(1,899)         $  469           $3,056          $ 6,450
  Basic earnings (loss) per
     share.......................     $ (0.20)         $ 0.05           $ 0.33          $  0.70
  Diluted earnings (loss) per
     share.......................     $ (0.20)         $ 0.05           $ 0.31          $  0.67
</Table>

                                       F-26
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     The sum of the individual quarterly basic and diluted earnings (loss) per
share amounts may not agree with year-to-date basic and diluted earnings (loss)
per share amounts as a result of each period's computation being based on the
weighted average number of common shares outstanding during that period.

     Second quarter results for 2002 were impacted by the recognition of revenue
associated with underaccruals in prior periods. This adjustment resulted in 142
MMcfe of additional production and $577,200 additional revenue. After adjusting
for related operating costs, the impact to net income for the second quarter of
2002 was an increase of $212,300.

     Included in operating expenses for the three months ended December 31, 2001
is $3.5 million for the settlement of litigation with BNP.

     Included in operating expenses for the three months ended March 31, 2001,
is a non-cash credit of $(755,372) to compensation expense as required by FASB
Interpretation No. (FIN) 44, Accounting for Certain Transactions involving Stock
Compensation. In the second quarter of 2001, an additional credit of $(95,353)
was included in operating expenses related to FIN 44.

13.  SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION,
     DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

     This footnote provides unaudited information required by SFAS No. 69,
"Disclosures About Oil and Natural Gas Producing Activities."

     Capitalized Costs -- Capitalized costs and accumulated depletion,
depreciation and amortization relating to the Company's oil and natural gas
producing activities, all of which are conducted within the continental United
States, are summarized below:

<Table>
<Caption>
                                                                  DECEMBER 31,
                                                           ---------------------------
                                                               2002           2001
                                                           ------------   ------------
<S>                                                        <C>            <C>
Developed oil and natural gas properties.................  $125,640,971   $101,303,892
Unevaluated oil and natural gas properties...............     7,901,315     13,105,817
Accumulated depletion, depreciation and amortization.....   (58,917,399)   (49,220,255)
                                                           ------------   ------------
Net capitalized cost.....................................  $ 74,624,887   $ 65,189,454
                                                           ============   ============
</Table>

     Costs Incurred -- Costs incurred in oil and natural gas property
acquisition, exploration and development activities are summarized below:

<Table>
<Caption>
                                                        YEAR ENDED DECEMBER 31,
                                                ---------------------------------------
                                                   2002          2001          2000
                                                -----------   -----------   -----------
<S>                                             <C>           <C>           <C>
Acquisition Cost:
  Unproved properties.........................  $ 5,465,794   $ 7,052,246   $ 4,219,936
  Proved properties...........................    1,369,464     5,695,000            --
Exploration costs.............................    4,725,032    11,046,117     2,707,015
Development costs.............................    7,926,579     4,822,589     3,765,945
                                                -----------   -----------   -----------
  Total costs incurred........................  $19,486,869   $28,615,952   $10,692,896
                                                ===========   ===========   ===========
</Table>

                                       F-27
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     Results of Operations -- Results of operations for the Company's oil and
natural gas producing activities are summarized below:

<Table>
<Caption>
                                                        YEAR ENDED DECEMBER 31,
                                                ---------------------------------------
                                                   2002          2001          2000
                                                -----------   -----------   -----------
<S>                                             <C>           <C>           <C>
Oil and natural gas revenue...................  $20,911,294   $29,810,917   $23,774,416
Operating expenses:
  Oil and natural gas operating expenses and
     ad valorem taxes.........................    2,628,320     3,041,073     2,152,638
  Production taxes............................    1,203,270     1,959,593     1,802,300
  Depletion, depreciation and amortization....    9,697,144     8,737,101     6,961,634
                                                -----------   -----------   -----------
     Results of operations from oil and gas
       producing activities...................  $ 7,382,560   $16,073,150   $12,857,844
                                                ===========   ===========   ===========
</Table>

     Reserves -- Proved reserves are estimated quantities of oil and natural
gas, 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 reserves are proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods. Proved oil and natural gas reserve quantities
and the related discounted future net cash flows before income taxes (see
Standardized Measure) for the periods presented are based on estimates prepared
by Ryder Scott Company, independent petroleum engineers. Such estimates have
been prepared in accordance with guidelines established by the Securities and
Exchange Commission.

     The Company's net ownership interests in estimated quantities of proved oil
and natural gas reserves and changes in net proved reserves, all of which are
located in the continental United States, are summarized below.

<Table>
<Caption>
                                                               NATURAL GAS
                                                                  (MCF)
                                                         YEAR ENDED DECEMBER 31,
                                                   ------------------------------------
                                                      2002         2001         2000
                                                   ----------   ----------   ----------
<S>                                                <C>          <C>          <C>
Proved developed and undeveloped reserves
  Beginning of year..............................  38,934,000   25,360,000   20,761,000
  Revisions of previous estimates................  (5,579,800)  (3,800,400)     892,000
  Purchase of oil and gas properties.............     521,300    5,275,600           --
  Extensions and discoveries.....................   6,376,900   19,222,300    9,646,700
  Sales of natural gas properties................      (6,000)    (924,600)    (733,700)
  Production.....................................  (5,266,400)  (6,198,900)  (5,206,000)
                                                   ----------   ----------   ----------
     End of year.................................  34,980,000   38,934,000   25,360,000
                                                   ==========   ==========   ==========
Proved developed reserves at year end............  24,234,000   31,750,000   21,965,000
                                                   ==========   ==========   ==========
</Table>

                                       F-28
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

<Table>
<Caption>
                                                       OIL, CONDENSATE AND NATURAL GAS LIQUIDS
                                                                        (BBLS)
                                                               YEAR ENDED DECEMBER 31,
                                                       ----------------------------------------
                                                           2002          2001          2000
                                                       ------------   -----------   -----------
<S>                                                    <C>            <C>           <C>
Proved developed and undeveloped reserves
  Beginning of year..................................     978,361       720,090       701,382
  Revisions of previous estimates....................   1,090,845       (94,255)        7,568
  Purchase of oil and gas properties.................      62,939        47,340            --
  Extensions and discoveries.........................     491,519       538,108       197,400
  Sales of natural gas properties....................        (521)      (71,493)      (12,500)
  Production.........................................    (280,828)     (161,429)     (173,760)
                                                        ---------      --------      --------
     End of year.....................................   2,342,315       978,361       720,090
                                                        =========      ========      ========
Proved developed reserves at year end................   1,509,950       879,058       674,845
                                                        =========      ========      ========
</Table>

     Standardized Measure -- The Standardized Measure of Discounted Future Net
Cash Flows relating to the Company's ownership interests in proved oil and
natural gas reserves for each of the three years ended December 31, 2002 is
shown below:

<Table>
<Caption>
                                                      YEAR ENDED DECEMBER 31,
                                             ------------------------------------------
                                                 2002           2001           2000
                                             ------------   ------------   ------------
<S>                                          <C>            <C>            <C>
Future cash inflows........................  $212,064,453   $129,715,973   $285,318,442
Future oil and natural gas operating
  expenses.................................   (33,151,831)   (23,105,695)   (33,271,286)
Future development costs...................    (8,069,700)    (7,810,246)    (2,921,526)
Future income tax expense..................   (36,475,435)   (16,116,421)   (73,922,604)
                                             ------------   ------------   ------------
Future net cash flows......................   134,367,487     82,683,611    175,203,026
10% discount factor........................   (36,811,015)   (19,400,764)   (49,844,011)
                                             ------------   ------------   ------------
Standardized measure of discounted future
  net cash flows...........................  $ 97,556,472   $ 63,282,847   $125,359,015
                                             ============   ============   ============
</Table>

     Future cash flows are computed by applying year-end prices of oil and
natural gas to year-end quantities of proved oil and natural gas reserves.
Future oil and natural gas operating expenses and development costs are computed
primarily by the Company's petroleum engineers and are provided to Ryder Scott
as estimates of expenditures to be incurred in developing and producing the
Company's proved oil and natural gas reserves at the end of the year, based on
year end costs and assuming the continuation of existing economic conditions.

     Future income taxes are based on year-end statutory rates, adjusted for net
operating loss carryforwards and tax credits. A discount factor of 10% was used
to reflect the timing of future net cash flows. The Standardized Measure of
Discounted Future Net Cash Flows is not intended to represent the replacement
cost or fair market value of the Company's oil and natural gas properties.

     The Standardized Measure of Discounted Future Net Cash Flows does not
purport, nor should it be interpreted, to present the fair value of the
Company's oil and natural gas reserves. An estimate of fair value would also
take into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs, a discount
factor more representative of the time value of money and the risks inherent in
reserve estimates.

                                       F-29
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     Changes in Standardized Measure -- Changes in Standardized Measure of
Discounted Future Net Cash Flows relating to proved oil and gas reserves are
summarized below:

<Table>
<Caption>
                                                      YEAR ENDED DECEMBER 31,
                                            -------------------------------------------
                                                2002           2001            2000
                                            ------------   -------------   ------------
<S>                                         <C>            <C>             <C>
Changes due to current year operations:
  Sales of oil and natural gas, net of oil
     and natural gas operating expenses...  $(17,079,705)  $ (24,810,251)  $(19,819,478)
  Sales of oil and natural gas
     properties...........................        (5,629)     (5,295,221)    (1,274,036)
  Purchase of oil and gas properties......     1,402,730       4,050,393             --
  Extensions and discoveries..............    15,519,251      43,653,229     80,545,294
Changes due to revisions of standardized
  variables:
  Prices and operating expenses...........    38,029,737    (121,516,045)    66,248,224
  Revisions of previous quantity
     estimates............................     2,378,838      (7,971,645)     3,881,207
  Estimated future development costs......       (20,172)     (4,258,998)       553,576
  Income taxes............................   (11,143,442)     40,956,396    (47,083,522)
  Accretion of discount...................     6,328,285      12,535,901      3,406,135
  Production rates (timing) and other.....    (1,136,268)        580,073      4,840,263
                                            ------------   -------------   ------------
Net change................................    34,273,625     (62,076,168)    91,297,663
Beginning of year.........................    63,282,847     125,359,015     34,061,352
                                            ------------   -------------   ------------
End of year...............................  $ 97,556,472   $  63,282,847   $125,359,015
                                            ============   =============   ============
</Table>

     Sales of oil and natural gas, net of oil and natural gas operating expenses
are based on historical pre-tax results. Sales of oil and natural gas
properties, extensions and discoveries, purchases of minerals in place and the
changes due to revisions in standardized variables are reported on a pre-tax
discounted basis, while the accretion of discount is presented on an after tax
basis.

14.  RECENT DEVELOPMENTS

     In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 141, "Business
Combinations," which requires the use of the purchase method of accounting for
business combinations initiated after June 30, 2001 and eliminates the
pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142,
"Goodwill and Other Intangible Assets," which discontinues the practice of
amortizing goodwill and indefinite lived intangible assets and initiates an
annual review of impairment. The new standard also requires that, at a minimum,
all intangible assets be aggregated and presented as a separate line item in the
balance sheet. The adoption of SFAS No. 141 and 142 had no impact on the
Company's financial position or results of operations

     A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and 142 to companies in the extractive industries,
including oil and gas companies. The issue is whether SFAS No. 141 requires
registrants to classify the costs of mineral rights associated with extracting
oil and gas as intangible assets in the balance sheet, apart from other
capitalized oil and gas property costs, and provide specific footnote
disclosures. Historically, the Company has included the costs of mineral rights
associated with extracting oil and gas as a component of oil and gas properties.
If it is ultimately determined that SFAS No. 141 requires oil and gas companies
to classify costs of mineral rights associated with extracting oil and gas as a
separate intangible assets line item on the balance sheet, the Company would be
required to reclassify approximately $8.8 million and $5.5 million at December
31, 2002 and 2001, respectively, out of oil

                                       F-30
<PAGE>
                           EDGE PETROLEUM CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

and gas properties and into a separate intangible assets line item. These costs
include those to acquire contract based drilling and mineral use rights such as
delay rentals, lease bonuses, commissions and brokerage fees, and other
leasehold costs. 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 full cost accounting rules, as allowed by SFAS
No. 142. Further, 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 the Company's compliance with covenants under its debt
agreements.

                                       F-31
<PAGE>

                        INDEPENDENT AUDITORS' REPORT ON
                   CONSOLIDATED FINANCIAL STATEMENT SCHEDULE

The Board of Directors and Stock holders
Edge Petroleum Corporation:

     Under date of March 14, 2003, we reported on the consolidated balance
sheets of Edge Petroleum Corporation as of December 31, 2002 and 2001, and the
related consolidated statements of operations, cash flows and stockholders'
equity for the years then ended. In connection with our audits of the
aforementioned consolidated financial statements, we also audited the related
consolidated financial statement schedule for the periods indicated above. This
consolidated financial statement schedule is the responsibility of the Company's
management. Our responsibility is to express an opinion on the consolidated
financial statement schedule based on our audits.

     In our opinion, the consolidated financial statement schedule, when
considered in relation to the basic consolidated financial statements taken as a
whole, presents fairly, in all material respect, the information set forth
therein.

                                          KPMG LLP

Houston, Texas
March 14, 2003

                                       F-32
<PAGE>

                                                                     SCHEDULE II

                           EDGE PETROLEUM CORPORATION

                 VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
              FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
                                 (IN THOUSANDS)

<Table>
<Caption>
                                                    BALANCE AT    CHARGED TO                BALANCE AT
                                                   BEGINNING OF   COSTS AND    DEDUCTIONS     END OF
                                                       YEAR        EXPENSES    AND OTHER       YEAR
                                                   ------------   ----------   ----------   ----------
<S>                                                <C>            <C>          <C>          <C>
YEAR ENDED DECEMBER 31, 2002:
  Allowance for doubtful accounts................      $688          $ --         $81          $607
YEAR ENDED DECEMBER 31, 2001:
  Allowance for doubtful accounts................      $163          $525         $--          $688
YEAR ENDED DECEMBER 31, 2000:
  Allowance for doubtful accounts................      $163          $ --         $--          $163
</Table>

                                       F-33
<PAGE>

                               INDEX TO EXHIBITS

<Table>
<C>            <S>   <C>
     2.1       --    Amended and Restated Combination Agreement by and among (i)
                     Edge Group II Limited Partnership, (ii) Gulfedge Limited
                     Partnership, (iii) Edge Group Partnership, (iv) Edge
                     Petroleum Corporation, (v) Edge Mergeco, Inc. and (vi) the
                     Company, dated as of January 13, 1997 (Incorporated by
                     reference from exhibit 2.1 to the Company's Registration
                     Statement on Form S-4 (Registration No. 333-17269)).
     3.1       --    Restated Certificate of Incorporation of the Company
                     (Incorporated by reference from exhibit 3.1 to the Company's
                     Registration Statement on Form S-1/A filed on February 5,
                     1997 (Registration No. 333-17267)).
     3.1A      --    Certificate of Amendment to the Restated Certificate of
                     Incorporation of the Company (Incorporated by reference from
                     exhibit 3.1 to the Company's Registration Statement on Form
                     S-1/A filed on February 5, 1997 (Registration No.
                     333-17267)).
     3.2       --    Bylaws of the Company (Incorporated by Reference from
                     exhibit 3.3 to the Company's Quarterly Report on Form 10-Q
                     for the quarterly period ended September 30, 1999).
     3.3       --    First Amendment to Bylaws of the Company on September 28,
                     1999 (Incorporated by Reference from exhibit 3.2 to the
                     Company's Quarterly Report on Form 10-Q for the quarterly
                     period ended September 30, 1999).
     4.1       --    Second Amended and Restated Credit Agreement dated October
                     6, 2000 by and between Edge Petroleum Corporation, Edge
                     Petroleum Exploration Company and Edge Petroleum Operating
                     Company, Inc. (collectively, the "Borrowers") and Union Bank
                     Of California, N.A., a national banking association, as
                     Agent for itself and as lender. (Incorporated by Reference
                     from exhibit 4.5 to the Company's Quarterly Report on Form
                     10-Q for the quarterly period ended September 31, 2000).
     4.2       --    Amendment No. 1 and Waiver dated as of November 11, 2001 by
                     and among the lenders party to the Second Amended and
                     Restated Credit Agreement dated October 6, 2000 ("Lenders"),
                     Union Bank of California, N.A., a national banking
                     association, as agent for such Lenders, Edge Petroleum
                     Corporation, Edge Petroleum Exploration Company, and Edge
                     Petroleum Operating Company, Inc. (collectively, the
                     "Borrowers"), as borrowers under the Second Amended and
                     Restated Credit Agreement. (Incorporated by Reference from
                     exhibit 4.2 to the Company's Annual Report on Form 10K for
                     the annual period ended December 31, 2001).
    +4.3       --    Amendment No. 2 dated as of May 29, 2002 by and among the
                     lenders party to the Second Amended and Restated Credit
                     Agreement dated October 6, 2000 ("Lenders"), Union Bank of
                     California, N.A., a national banking association, as agent
                     for such Lenders, Edge Petroleum Corporation, Edge Petroleum
                     Exploration Company, and Edge Petroleum Operating Company,
                     Inc. (collectively, the "Borrowers"), as borrowers under the
                     Second Amended and Restated Credit Agreement.
    +4.4       --    Amendment No. 3 dated as of August 8, 2002 by and among the
                     lenders party to the Second Amended and Restated Credit
                     Agreement dated October 6, 2000 ("Lenders"), Union Bank of
                     California, N.A., a national banking association, as agent
                     for such Lenders, Edge Petroleum Corporation, Edge Petroleum
                     Exploration Company, and Edge Petroleum Operating Company,
                     Inc. (collectively, the "Borrowers"), as borrowers under the
                     Second Amended and Restated Credit Agreement.
     4.5       --    Letter Agreement dated October 31, 2000 by and between Edge
                     Petroleum Corporation, Edge Petroleum Exploration Company
                     and Edge Petroleum Operating Company, Inc. (collectively,
                     the "Borrowers") and Union Bank Of California, N.A., a
                     national banking association, as Agent for itself and as
                     lender. (Incorporated by Reference from exhibit 4.6 to the
                     Company's Quarterly Report on Form 10-Q for the quarterly
                     period ended September 31, 2000).
     4.6       --    Letter Agreement dated March 23, 2001 by and between Edge
                     Petroleum Corporation, Edge Petroleum Exploration Company
                     and Edge Petroleum Operating Company, Inc. (collectively,
                     the "Borrowers") and Union Bank Of California, N.A., a
                     national banking association, as Agent for itself and as
                     lender. (Incorporated by Reference from exhibit 4.5 to the
                     Company's Annual Report on Form 10K for the annual period
                     ended December 31, 2000).
</Table>
<PAGE>
<Table>
<C>            <S>   <C>
     4.7       --    Letter Agreement dated September 21, 2001 by and between
                     Edge Petroleum Corporation, Edge Petroleum Exploration
                     Company and Edge Petroleum Operating Company, Inc.
                     (collectively, the "Borrowers") and Union Bank Of
                     California, N.A., a national banking association, as Agent
                     for itself and as lender. (Incorporated by Reference from
                     exhibit 4.6 to the Company's Quarterly Report on Form 10Q
                     for the quarterly period ended September 30, 2001).
     4.8       --    Letter Agreement dated January 18, 2002 by and between Edge
                     Petroleum Corporation, Edge Petroleum Exploration Company
                     and Edge Petroleum Operating Company, Inc. (collectively,
                     the "Borrowers") and Union Bank Of California, N.A., a
                     national banking association, as Agent for itself and as
                     lender. (Incorporated by Reference from exhibit 4.6 to the
                     Company's Annual Report on Form 10K for the annual period
                     ended December 31, 2001).
     4.9       --    Letter Agreement dated August 9, 2002 by and between Edge
                     Petroleum Corporation, Edge Petroleum Exploration Company
                     and Edge Petroleum Operating Company, Inc. (collectively,
                     the "Borrowers") and Union Bank Of California, N.A., a
                     national banking association, as Agent for itself and as
                     lender. (Incorporated by Reference from exhibit 4.7 to the
                     Company's Quarterly Report on Form 10Q for the quarterly
                     period ended June 30, 2002).
     4.10      --    Common Stock Subscription Agreement dated as of April 30,
                     1999 between the Company and the purchasers named therein
                     (Incorporated by reference from exhibit 4.5 to the Company's
                     Quarterly Report on Form 10-Q/A for the quarter ended March
                     31, 1999).
     4.11      --    Warrant Agreement dated as of May 6, 1999 between the
                     Company and the Warrant holders named therein (Incorporated
                     by reference from exhibit 4.5 to the Company's Quarterly
                     Report on Form 10-Q/A for the quarter ended March 31, 1999).
     4.12      --    Form of Warrant for the purchase of the Common Stock
                     (Incorporated by reference from the Common Stock
                     Subscription Agreement from exhibit 4.5 to the Company's
                     Quarterly Report on Form 10-Q/A for the quarter ended March
                     31, 1999).
    10.1       --    Joint Venture Agreement between Edge Joint Venture II and
                     Essex Royalty Limited Partnership II, dated as of May 10,
                     1994 (Incorporated by reference from exhibit 10.2 to the
                     Company's Registration Statement on Form S-4 (Registration
                     No. 333-17269)).
    10.2       --    Joint Venture Agreement between Edge Joint Venture II and
                     Essex Royalty Limited Partnership, dated as of April 11,
                     1992 (Incorporated by reference from exhibit 10.3 to the
                     Company's Registration Statement on Form S-4 (Registration
                     No. 333-17269)).
   +10.3       --    Amendment dated August 21, 2000 to the Joint Venture
                     Agreement between Edge Joint Venture II and Essex Royalty
                     Limited Partnership II, dated as of May 10, 1994.
   +10.4       --    Amendment dated August 21, 2000 to the Joint Venture
                     Agreement between Edge Joint Venture II and Essex Royalty
                     Limited Partnership, dated as of April 11, 1992.
   +10.5       --    Letter Agreement between Edge Petroleum Corporation and
                     Essex Royalty Limited Partnership, dated as of July 30,
                     2002.
    10.6       --    Form of Indemnification Agreement between the Company and
                     each of its directors (Incorporated by reference from
                     exhibit 10.7 to the Company's Registration Statement on Form
                     S-4 (Registration No. 333-17269)).
    10.7       --    Stock Option Plan of Edge Petroleum Corporation, a Texas
                     corporation (Incorporated by reference from exhibit 10.13 to
                     the Company's Registration Statement on Form S-4
                     (Registration No. 333-17269)).
    10.8       --    Employment Agreement dated as of November 16, 1998, by and
                     between the Company and John W. Elias. (Incorporated by
                     reference from 10.12 to the Company's Annual Report on Form
                     10-K for the year ended December 31, 1998).
   +10.9       --    Incentive Plan of Edge Petroleum Corporation as Amended and
                     Restated Effective as of February 20, 2003.
    10.10      --    Edge Petroleum Corporation Incentive Plan "Standard
                     Non-Qualified Stock Option Agreement" by and between Edge
                     Petroleum Corporation and the Officers named therein.
                     (Incorporated by reference from exhibit 10.2 to the
                     Company's Quarterly Report on Form 10-Q for the quarterly
                     period ended September 30, 1999).
    10.11      --    Edge Petroleum Corporation Incentive Plan "Director
                     Non-Qualified Stock Option Agreement" by and between Edge
                     Petroleum Corporation and the Directors named therein.
                     (Incorporated by reference from exhibit 10.3 to the
                     Company's Quarterly Report on Form 10-Q for the quarterly
                     period ended September 30, 1999).
</Table>
<PAGE>
<Table>
<C>            <S>   <C>
    10.12      --    Form of Employee Restricted Stock Award Agreement under the
                     Incentive Plan of Edge Petroleum Corporation (Incorporated
                     by Reference from exhibit 10.15 to the Company's Quarterly
                     Report on Form 10-Q/A for the quarterly period ended March
                     31, 1999).
    10.13      --    Edge Petroleum Corporation Amended and Restated Elias Stock
                     Incentive Plan. (Incorporated by reference from exhibit 4.5
                     to the Company's Registration Statement on Form S-8 filed
                     May 30, 2001 (Registration No. 333-61890)).
    10.14      --    Form of Edge Petroleum Corporation John W. Elias
                     Non-Qualified Stock Option Agreement (Incorporated by
                     reference from exhibit 4.6 to the Company's Registration
                     Statement on Form S-8 filed May 30, 2001 (Registration No.
                     333-61890)).
   +21.1       --    Subsidiaries of the Company.
   *23.1       --    Consent of KPMG LLP, independent auditors.
   *23.2       --    Consent of Deloitte & Touche LLP.
   *23.3       --    Consent of Ryder Scott Company.
   *31.1       --    Certification by John W. Elias, Chief Executive Officer,
                     pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the
                     Securities Exchange Act of 1934.
   *31.2       --    Certification by Michael G. Long , Chief Financial and
                     Accounting Officer, pursuant to Rule 13a-14(a) or Rule
                     15d-14(a) under the Securities Exchange Act of 1934.
   *32.1       --    Certification by John W. Elias, Chief Executive Officer,
                     pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
                     (Subsections (a) and (b) of Section 1350, Chapter 63 of
                     Title 18, United States Code).
   *32.2       --    Certification by Michael G. Long, Chief Financial and
                     Accounting Officer, pursuant to Section 906 of the
                     Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of
                     Section 1350, Chapter 63 of Title 18, United States Code).
   +99.1       --    Summary of Reserve Report of Ryder Scott Company Petroleum
                     Engineers as of December 31, 2002.
</Table>

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

* Filed herewith.

+ Previously filed.