<PAGE>

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

                                    FORM 10-Q

    [ x ]   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934

                  For the quarterly period ended June 30, 2003

                                       OR

    [  ]    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934

          For the transition period from _________________ to _____________

                         Commission file number 0-22149

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

                  Delaware                              76-0511037
       (State or other jurisdiction of               (I.R.S. Employer
       incorporation or organization)                Identification No.)

                                  Travis Tower
                             1301 Travis, Suite 2000
                              Houston, Texas 77002
                    (Address of principal executive offices)
                                   (Zip code)

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

  Indicate by checkmark 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 whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [x]

  Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.

<TABLE>
<CAPTION>
    Class                            Outstanding at August 11, 2003
    -----                            ------------------------------
<S>                                  <C>
Common Stock                                     9,521,251
</TABLE>


<PAGE>


                          PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EDGE PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                                                        June 30,        December 31,
                                                                                          2003             2002
                                                                                      ------------     -------------
                                                                                      (Unaudited)
<S>                                                                                   <C>              <C>
ASSETS
CURRENT ASSETS:
  Cash and cash equivalents                                                           $  3,916,512      $  2,568,176
  Accounts receivable, trade, net of allowance of $525,248 at June 30, 2003 and
    December 31, 2002                                                                    8,003,153         5,617,648
  Accounts receivable, joint interest owners, net of allowance of $82,000 at June
    30, 2003 and December 31, 2002                                                         453,944           403,446
  Current deferred tax asset                                                             1,161,724           832,343
  Other current assets                                                                     940,788           430,930
                                                                                      ------------      ------------

    Total current assets                                                                14,476,121         9,852,543

PROPERTY AND EQUIPMENT, Net - full cost method of accounting for oil and natural
  gas properties (unevaluated of $5.3 million and $7.9 million at June 30, 2003
  and December 31, 2002, respectively)                                                   78,145,295        75,681,772

DEFERRED TAX ASSET                                                                              --            41,338
                                                                                      ------------      ------------

TOTAL ASSETS                                                                          $ 92,621,416      $ 85,575,653
                                                                                      ============      ============

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
  Accounts payable, trade                                                             $    758,730      $  1,533,972
  Accrued liabilities                                                                    6,001,713         3,586,843
  Accrued interest                                                                         169,332           127,698
  Asset retirement obligation                                                              166,284                --
  Derivative financial instruments                                                       2,037,573         1,293,840
                                                                                      ------------      ------------

    Total current liabilities                                                            9,133,632         6,542,353

ASSET RETIREMENT OBLIGATION                                                                860,078                --

DEFERRED TAX LIABILITY                                                                   1,133,180                --

LONG-TERM DEBT                                                                          21,000,000        20,500,000
                                                                                      ------------      ------------

    Total liabilities                                                                   32,126,890        27,042,353
                                                                                      ------------      ------------

COMMITMENTS AND CONTINGENCIES (Note 10)

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; 9,517,266 and
     9,416,254 shares issued and outstanding at June 30, 2003 and December 31,
     2002, respectively                                                                     95,172            94,163
  Additional paid-in capital                                                            56,923,862        56,663,626
  Retained earnings                                                                      4,730,840         2,616,507
  Accumulated other comprehensive loss                                                  (1,255,348)         (840,996)
                                                                                      ------------      ------------

    Total stockholders' equity                                                          60,494,526        58,533,300
                                                                                      ------------      ------------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                                            $ 92,621,416      $ 85,575,653
                                                                                      ============      ============
</TABLE>

          See accompanying notes to consolidated financial statements.

                                       1


<PAGE>


EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

<TABLE>
<CAPTION>
                                                         Three Months Ended               Six Months Ended
                                                               June 30,                        June 30,
                                                     ----------------------------    ----------------------------
                                                        2003            2002            2003            2002
                                                     ------------    ------------    ------------    ------------
<S>                                                  <C>             <C>             <C>             <C>
OIL AND NATURAL GAS REVENUE                          $  7,994,395    $  6,432,149    $ 14,833,165    $ 11,339,746

OPERATING EXPENSES:
  Lifting costs                                           550,998         600,564       1,145,802       1,196,809
  Severance and ad valorem taxes                          521,904         450,241       1,041,059         885,963
  Depletion, depreciation and amortization              2,844,571       2,694,566       5,577,356       5,526,729
  Accretion expense                                        14,765              --          29,853              --
  General and administrative expenses                   1,520,531       1,473,225       2,863,457       2,819,521
                                                     ------------    ------------    ------------    ------------

    Total operating expenses                            5,452,769       5,218,596      10,657,527      10,429,022
                                                     ------------    ------------    ------------    ------------

OPERATING INCOME                                        2,541,626       1,213,553       4,175,638         910,724

OTHER INCOME AND EXPENSE:
  Interest income                                           3,025           3,267           5,148           7,145
  Interest expense, net                                  (165,046)        (25,343)       (341,435)        (50,687)
                                                     ------------    ------------    ------------    ------------

INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT
   OF ACCOUNTING CHANGE                                 2,379,605       1,191,477       3,839,351         867,182

INCOME TAX EXPENSE                                       (845,471)       (427,492)     (1,367,193)       (310,105)
                                                     ------------    ------------    ------------    ------------

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING
  CHANGE                                                1,534,134         763,985       2,472,158         557,077

CUMULATIVE EFFECT OF ACCOUNTING CHANGE                         --              --        (357,825)             --
                                                     ------------    ------------    ------------    ------------
NET INCOME                                           $  1,534,134    $    763,985    $  2,114,333    $    557,077
                                                     ============    ============    ============    ============

BASIC EARNINGS PER SHARE:
Net income before cumulative effect of accounting
   change                                            $       0.16    $       0.08    $       0.26    $       0.06
Cumulative effect of accounting change                         --              --           (0.04)             --
                                                     ------------    ------------    ------------    ------------
Basic earnings per share                             $       0.16    $       0.08    $       0.22    $       0.06
                                                     ============    ============    ============    ============

DILUTED EARNINGS PER SHARE:
 Net income before cumulative effect of accounting
  change                                             $       0.16    $       0.08    $       0.26    $       0.06
Cumulative effect of accounting change                         --              --           (0.04)             --
                                                     ------------    ------------    ------------    ------------
Diluted earnings per share                           $       0.16    $       0.08    $       0.22    $       0.06
                                                     ============    ============    ============    ============

BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES
   OUTSTANDING                                          9,502,255       9,391,267       9,471,227       9,358,253
                                                     ============    ============    ============    ============

DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES
   OUTSTANDING                                          9,709,192       9,695,245       9,641,851       9,647,045
                                                     ============    ============    ============    ============
</TABLE>

          See accompanying notes to consolidated financial statements.

                                       2


<PAGE>


EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

<TABLE>
<CAPTION>
                                                                                     Six Months Ended June 30,
                                                                                    --------------------------
                                                                                       2003           2002
                                                                                    -----------    -----------
<S>                                                                                 <C>            <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income                                                                          $ 2,114,333    $   557,077
Adjustments to reconcile net income to net cash provided by operating activities:
    Cumulative effect of accounting change                                              357,825             --
    Deferred income taxes                                                             1,367,193        310,105
    Depletion, depreciation and amortization                                          5,577,356      5,526,729
    Accretion expense                                                                    29,853             --
    Amortization of deferred loan costs                                                      --         50,687
    Deferred compensation                                                               176,439        210,310
Changes in assets and liabilities:
    Increase in accounts receivable, trade                                           (2,385,505)      (945,260)
    Increase in accounts receivable, joint interest owners                              (50,498)      (672,746)
    Increase in other assets                                                           (509,858)      (526,522)
    Increase (decrease) in accounts payable, trade                                     (775,242)       344,714
    Increase (decrease) in accrued liabilities                                        2,446,177     (2,490,864)
    Increase in accrued interest payable                                                 41,634         58,299
                                                                                    -----------    -----------

      Net cash provided by operating activities                                       8,389,707      2,422,529
                                                                                    -----------    -----------

CASH FLOWS FROM INVESTING ACTIVITIES:
  Oil and natural gas property and equipment additions                               (7,649,966)    (8,558,367)
  Proceeds from the sale of oil and natural gas properties                               55,096             --
                                                                                    -----------    -----------

      Net cash used in investing activities                                          (7,594,870)    (8,558,367)
                                                                                    -----------    -----------

CASH FLOWS FROM FINANCING ACTIVITIES:
  Borrowings from long-term debt                                                      1,700,000      6,500,000
  Payments of long-term debt                                                         (1,200,000)      (500,000)
  Net proceeds from issuance of common stock                                             53,499         47,400
                                                                                    -----------    -----------

      Net cash provided by financing activities                                         553,499      6,047,400
                                                                                    -----------    -----------

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                                  1,348,336        (88,438)

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD                                        2,568,176        793,287
                                                                                    -----------    -----------

CASH AND CASH EQUIVALENTS, END OF PERIOD                                            $ 3,916,512    $   704,849
                                                                                    ===========    ===========
</TABLE>

          See accompanying notes to consolidated financial statements.

                                       3


<PAGE>


EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (UNAUDITED)

<TABLE>
<CAPTION>
                                                                                                 Accumulated
                                     Common Stock               Additional                          Other             Total
                             -----------------------------        Paid-in         Retained       Comprehensive     Stockholders'
                                Shares           Amount           Capital         Earnings           Loss             Equity
                             ------------     ------------     ------------     ------------     -------------     -------------
<S>                          <C>              <C>              <C>              <C>              <C>               <C>
BALANCE, DECEMBER 31, 2002      9,416,254     $     94,163     $ 56,663,626     $  2,616,507     $   (840,996)     $ 58,533,300

Exercise of stock
  options                          19,250              192           53,307               --               --            53,499

Issuance of stock                  81,762              817           30,490               --               --            31,307

Deferred compensation
  expense                              --               --          176,439               --               --           176,439

Change in valuation of
  hedging instruments                  --               --               --               --         (414,352)         (414,352)

Net income                             --               --               --        2,114,333               --         2,114,333
                             ------------     ------------     ------------     ------------     ------------      ------------
BALANCE,
  JUNE 30, 2003                 9,517,266     $     95,172     $ 56,923,862     $  4,730,840     $ (1,255,348)     $ 60,494,526
                             ============     ============     ============     ============     ============      ============
</TABLE>

          See accompanying notes to consolidated financial statements.

                                        4


<PAGE>


EDGE PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

         The financial statements included herein have been prepared by Edge
Petroleum Corporation, a Delaware corporation ("we", "our", "us" or the
"Company"), without audit pursuant to the rules and regulations of the
Securities and Exchange Commission, and reflect all adjustments which are, in
the opinion of management, necessary to present a fair statement of the results
for the interim periods on a basis consistent with the annual audited
consolidated financial statements. All such adjustments are of a normal
recurring nature. The results of operations for the interim periods are not
necessarily indicative of the results to be expected for an entire year. Certain
information, accounting policies and footnote disclosures normally included in
financial statements prepared in accordance with accounting principles generally
accepted in the United States of America have been omitted pursuant to such
rules and regulations, although we believe that the disclosures are adequate to
make the information presented not misleading. These financial statements should
be read in conjunction with our audited consolidated financial statements
included in our Annual Report on Form 10-K for the year ended December 31, 2002.

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

         ACCOUNTING CHANGE - In July 2001, the Financial Accounting Standards
Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No.
143, "Accounting for Asset Retirement Obligations." See Note 2.

         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 and
constitute one cost center.

         In accordance with the full cost method of accounting, we capitalize 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 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. Intangible assets with a determinable useful life
will continue to be amortized over that period. The amortization provisions
apply to goodwill and intangible assets acquired after June 30, 2001. The SEC is
currently reviewing the application of the accounting prescribed by these
statements to the oil and natural gas industry. The result may be to require
that mineral use rights, such as leasehold interests, be separately classified
in the balance sheets of oil and natural gas companies. Specifically, these
standards may require that mineral use rights, including proved leaseholds
acquired in a business combination, be classified on the balance sheet as
intangible assets for all leaseholds acquired subsequent to June 30, 2001. We
did not change or reclassify contractual mineral rights

                                       5


<PAGE>


included in developed and unevaluated oil and gas properties on our balance
sheet upon adoption of SFAS No. 141 and 142. We believe the treatment of such
mineral rights as tangible assets under the full cost method of accounting for
oil and gas properties is appropriate. If it is determined that reclassification
is necessary, we would be required to reduce our developed and unevaluated
properties and to instead report intangible mineral rights related to developed
and unevaluated properties. The Company believes that the provisions of SFAS No.
141 and 142 impact only the balance sheet and any associated footnote
disclosures. Any reclassifications potentially required would not impact our
cash flows or statements of operations, since these costs would continue to be
depleted in accordance with the full cost method of accounting for oil and gas
companies.

         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 accumulated
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 impairment related to the ceiling test
was required during the six-month periods ended June 30, 2003 or 2002.

         In May 2003, the Securities and Exchange Commission ("SEC") issued
Staff Accounting Bulletin ("SAB") No. 103, "Update of Codification of Staff
Accounting Bulletins." SAB No. 103 revises or rescinds portions of the
interpretive guidance included in the codification of staff accounting bulletins
in order to make this interpretive guidance consistent with current
authoritative accounting and auditing guidance and SEC rules and regulations.
The principal revisions relate to the rescission of material no longer necessary
because of private sector developments in U.S. generally accepted accounting
principles, as well as SEC rulemaking. As specifically related to oil and gas
producing activities, it requires the inclusion of cash flow hedges in the
computation of limitation on capitalized costs. In the second quarter of 2003,
the Company adopted these provisions and included the effects of hedge gains and
losses in the ceiling test. Impairment of oil and natural gas properties is
assessed on a quarterly basis.

         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.

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

                                       6


<PAGE>


<TABLE>
<CAPTION>
                                                Three Months Ended June 30,           Six Months Ended  June 30,
                                             -------------------------------       --------------------------------
                                                  2003              2002              2003                2002
                                             --------------      -----------       -------------      -------------
<S>                                          <C>                 <C>               <C>                <C>
Net income as reported                       $    1,534,134      $   763,985       $   2,114,333      $     557,077
  Add:
    Stock based employee compensation
    expense (benefit) included in
    reported net income, net of
    related income tax                                   --               --                  --               (195)
  Deduct:
    Total stock based employee compensation
    expense determined under fair value
    based method for all awards, net of
    related income tax                              (56,513)         (75,604)           (114,322)          (124,296)
                                             --------------      -----------       -------------      -------------
Pro forma net income                         $    1,477,621      $   688,381       $   2,000,011      $     432,586
                                             ==============      ===========       =============      =============

Earnings Per Share:
     Basic - as reported                     $         0.16      $      0.08       $        0.22      $        0.06
     Basic - pro forma                                 0.16             0.07                0.21               0.05

     Diluted - as reported                   $         0.16      $      0.08       $        0.22      $        0.06
     Diluted - pro forma                               0.15             0.07                0.21               0.04
</TABLE>

         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 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 and re-priced in May
1999, as well as certain options newly issued in conjunction with the repricing.
No adjustments related to FIN 44 were required during the six-month period ended
June 30, 2003. No adjustments related to FIN 44 were required during the three
months ended June 30, 2002 and a credit of $(303) was reported for the six
months ended June 30, 2002.

ACCOUNTING PRONOUNCEMENTS

         In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts
(collectively referred to as derivatives) and for hedging activities under SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities". SFAS
No. 149 is effective for contracts entered into or modified after June 30, 2003.
The Company has not entered into any applicable contracts since June 30, 2003.

         In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity". SFAS
No. 150 established standards for classification and measurement in the
statement of financial position of certain financial instruments with
characteristics of both liabilities and equity. It requires classification of a
financial instrument that is within its scope as a liability (or an asset in
some circumstances). SFAS 150 is effective for financial instruments entered
into or modified after May 31, 2003, and otherwise is effective at the beginning
of the first interim period beginning after June 15, 2003. This statement is
currently not applicable to any of the Company's financial instruments.

         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

                                       7


<PAGE>


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.

         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 impact on the Company's future financial condition
or results of operations.

2. ASSET RETIREMENT OBLIGATION

         In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations". The statement requires entities to record a liability
for legal obligations associated with the retirement of tangible long-lived
assets in the period in which they are incurred. When the liability for the fair
value of dismantlement and abandonment costs, excluding salvage values, is
initially recorded, the carrying amount of the related long-lived asset, oil and
gas properties, is increased. Accretion of the liability is recognized each
period using the interest method of allocation, and the capitalized cost is
depleted 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. The standard is effective for fiscal years beginning
after June 15, 2002, therefore the Company 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
accretion and depletion.

         At January 1, 2003, the Company recorded the present value of its
future Asset Retirement Obligation ("ARO") for oil and natural gas property and
related equipment. The cumulative effect of the adoption of SFAS No. 143 and the
change in accounting principle was a charge to net income during the first
quarter of 2003 of $357,825, net of taxes of $192,675. The changes to the ARO
during the period ended June 30, 2003 are as follows:

<TABLE>
<S>                                            <C>
ARO at January 1, 2003                         $   942,736

Liabilities incurred in the current period          63,487

Liabilities settled in the current period               --

Accretion expense                                   29,853

Revisions                                           (9,714)
                                               -----------

ARO at June 30, 2003                           $ 1,026,362
                                               ===========
</TABLE>

         The following table summarizes the pro forma net income and earnings
per share for the three-month and six-month periods ended June 30, 2002 had
SFAS 143 been adopted by the Company on January 1, 2002.

                                       8


<PAGE>


<TABLE>
<CAPTION>
                                              For the three months ended               For the six months ended
                                                     June 30, 2002                            June 30, 2002
                                           ---------------------------------      ----------------------------------
                                            As Reported         Pro Forma          As Reported          Pro Forma
                                           --------------     --------------      --------------      --------------
<S>                                        <C>                <C>                 <C>                 <C>
Net income                                 $      763,985     $      754,451      $      557,077      $      174,383
Net income per share, basic                $         0.08     $         0.08      $         0.06      $         0.02
Net income per share, diluted              $         0.08     $         0.08      $         0.06      $         0.02
</TABLE>

         Had we applied the provisions of SFAS No. 143 as of January 1, 2002 the
pro forma amount of the ARO would have been $882,537.

3. LONG TERM DEBT

           During the first half of 2003, we borrowed $1.7 million and made
repayments of $1.2 million under our credit facility (the "Credit Facility") and
as of June 30, 2003, $21.0 million was outstanding under the credit facility.
Borrowings under the Credit Facility bear interest at a rate equal to prime plus
0.50% or LIBOR plus 2.75%. The Company chooses which interest rate will be
applied to a specific borrowing. The Credit Facility matures October 6, 2004 and
is secured by substantially all of our assets.

           Effective April 1, 2003, the borrowing base was increased to $26.5
million. The borrowing base will be re-determined again during the second half
of 2003. The borrowing base is not subject to automatic reductions at this time.

           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) 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. EBITDA was part of a negotiated covenant with our lender and is
presented here to define our requirements to comply with that covenant. The
Working Capital ratio requires that the amount of our consolidated current
assets less our consolidated 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 revenue, 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. At June 30, 2003, we were in compliance with
the above-mentioned covenants.

4. OTHER COMPREHENSIVE INCOME

         In accordance with SFAS No. 130, "Reporting Other Comprehensive
Income," the following are the components of Other Comprehensive Income:

<Table>
<Caption>
                                                                Three months ended           Six months ended
                                                                      June 30,                    June 30,
                                                              -----------------------     -----------------------
                                                                 2003          2002          2003          2002
                                                              ----------     --------     ----------     --------
<S>                                                           <C>            <C>          <C>            <C>
Net income                                                    $1,534,134     $763,985     $2,114,333     $557,077
Other comprehensive income (loss), net of tax:
  Unrealized hedge derivative fair value gain (loss)(1)          (10,610)          --       (860,727)          --
  Less: Reclassification to earnings of realized (gain)
        loss upon settlement of hedge derivative
        contracts(2)                                             165,814       70,539        446,375           --
                                                              ----------     --------     ----------     --------
  Total other comprehensive income (loss)                        155,204       70,539       (414,352)          --
                                                              ----------     --------     ----------     --------
Total comprehensive income                                    $1,689,338     $834,524     $1,699,981     $557,077
                                                              ==========     ========     ==========     ========

        (1) Net of Income Tax Expense                              6,611           --        583,774           --
        (2) Net of Income Tax Expense                            103,321       39,678        254,392           --
</Table>


5. EARNINGS PER SHARE

         We account for 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 during the periods, using the treasury stock
method.

         The following is a reconciliation of the numerators and denominators of
basic and diluted earnings per share computations, in accordance with SFAS No.
128, for the three-month and six-month periods ended June 30, 2003 and 2002:

                                       9


<PAGE>


<TABLE>
<CAPTION>
                                 Three Months Ended June 30, 2003                   Three Months Ended June 30, 2002
                         ----------------------------------------------        ------------------------------------------
                                                                 Per                                                Per
                            Income               Shares         Shares           Income             Share          Share
                          (Numerator)         (Denominator)     Amount         (Numerator)       (Denominator)    Amount
                         -------------        -------------   ---------        -----------       -------------   --------
<S>                      <C>                  <C>             <C>              <C>                <C>            <C>
BASIC EPS
Income available to
 common stockholders     $   1,534,134          9,502,255     $    0.16        $ 763,985           9,391,267     $   0.08
Effect of dilutive
 securities:
Restricted stock                    --            106,129            --               --             123,518           --
Common stock options                --            100,808            --               --             151,882           --
Warrants                            --                 --            --               --              28,578           --
                         -------------          ----------    ---------        ---------           ---------     --------
DILUTED EPS
Income available to
 common stockholders     $   1,534,134          9,709,192     $    0.16        $ 763,985           9,695,245     $   0.08
                         =============          =========     =========        =========           =========     ========
</TABLE>

<TABLE>
<CAPTION>
                                  Six Months Ended June 30, 2003                     Six Months Ended June 30, 2002
                         ----------------------------------------------        ------------------------------------------
                                                                Per                                                 Per
                            Income               Shares        Shares            Income             Share          Share
                          (Numerator)         (Denominator)    Amount          (Numerator)       (Denominator)    Amount
                         -------------        -------------   ---------        -----------       -------------   --------
<S>                      <C>                  <C>             <C>              <C>               <C>             <C>
BASIC EPS
Income available to
 common stockholders     $  2,114,333           9,471,227     $    0.22        $  557,077          9,358,253     $   0.06
Effect of dilutive
 securities:
Restricted stock                   --             101,080            --                --            151,062           --
Common stock options               --              69,544            --                --            130,455           --
Warrants                           --                  --            --                --              7,275           --
                         -------------          ---------     ---------        ----------          ---------     --------
DILUTED EPS
Income available to
 common stockholders     $  2,114,333           9,641,851     $    0.22        $  557,077          9,647,045     $   0.06
                         =============          =========     =========        ==========          =========     ========
</TABLE>

6. INCOME TAXES

         We account for income taxes under the provisions of SFAS No. 109 -
"Accounting for Income Taxes," which provides for an asset and liability
approach in 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 temporary
differences between the carrying amounts of assets and liabilities for financial
reporting purposes and the amounts calculated for income tax purposes.

         We currently estimate that our effective tax rate for the year ending
December 31, 2003 will be approximately 35.6%. A provision for income taxes of
$1.4 million and $310,100 was reported for the six months ended June 30, 2003
and 2002, respectively.

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

         A summary of non-cash investing and financing activities for the six
months ended June 30, 2003 and 2002 is presented below:

                                       10


<PAGE>


<TABLE>
<CAPTION>
                                                              Number of
                                                               shares      Fair Market
                    Description                                issued         Value
---------------------------------------------------------     ---------    ------------
<S>                                                           <C>          <C>
SIX MONTHS ENDED JUNE 30, 2003:
Shares issued to satisfy restricted stock grants                73,962       $390,238
Shares issued to fund the Company's matching contribution
  under the Company's 401 (k) plan                               7,800       $ 31,307
SIX MONTHS ENDED JUNE 30, 2002:
Shares issued to satisfy restricted stock grants                74,736       $402,429
Shares issued to fund the Company's matching contribution
  under the Company's 401 (k) plan                               3,831       $ 20,266
</TABLE>

         We consider all highly liquid debt instruments purchased with an
original maturity of three months or less to be cash equivalents.

Supplemental Disclosure of Cash Flow Information

<TABLE>
<CAPTION>
                                                     For the Six Months Ended
                                                            June 30,
                                                   ----------------------------
                                                       2003              2002
                                                   -------------       --------
<S>                                                <C>                 <C>
Cash paid during the period for:
  Interest, net of amounts capitalized             $     172,103       $     --
</TABLE>

         Interest paid for the six months ended June 30, 2003 and 2002 excludes
amounts capitalized of $124,012 and $290,168, respectively.

8. HEDGING ACTIVITIES

         Due to the instability of oil and natural gas prices, we periodically
enter into 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 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.

         The following was the impact on oil and natural gas revenue from
hedging activities for the six months ended June 30, 2003 and 2002:

<TABLE>
<CAPTION>
Hedge Type              Effective Dates                         MMBtu          Six Months Ended June 30,
-----------          --------------------     Price Per        Volumes     ----------------------------------
                      Beg.        Ending        MMBtu          Per Day          2003                 2002
-----------          ------      --------     ---------        -------     ---------------      -------------
<S>                  <C>         <C>          <C>              <C>         <C>                  <C>
Natural Gas                                    $4.00 -
 Collar              1/1/03      12/31/03      $4.25            10,000     $    (3,335,880)     $          --
Natural Gas                                    $5.00 -
 Collar              6/1/03       9/30/03      $6.50             2,000                  --                 --
Natural Gas
 Floor               4/1/02       6/30/02      $2.65             18,000                 --           (163,800)
                                                                           ---------------      -------------
                                                                           $    (3,335,880)     $    (163,800)
                                                                           ===============      =============
</TABLE>

         Our current hedging activities for natural gas are entered into on a
per MMbtu delivered price basis, NYMEX, with settlement for each calendar month
occurring five business days following the expiration date.

                                       11


<PAGE>


         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 June 30, 2003, the
market value of this outstanding hedge was approximately $(2.0) million and is
included in current liabilities.

         In April 2003, the Company entered into a natural gas collar covering
2,000 MMbtu per day for the period June 1, 2003 to September 30, 2003 with a
floor of $5.00 per MMbtu and a ceiling of $6.50 per MMbtu. At June 30, 2003, the
market value of this outstanding hedge was approximately $11,500 and is included
in current liabilities.

         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. The floor structure provided a minimum realized price for the
protected volume yet preserved any upside in gas prices. The natural gas floor
expired with no additional cost to the Company.

9. SUBSEQUENT EVENTS

         In May 2003, the Company announced its proposed merger with Miller
Exploration Company. The merger will be accounted for as a purchase of Miller by
Edge valued at approximately $12.7 million. Edge anticipates that the two
companies will be in a position to hold shareholders' meetings to approve the
transaction early in the fourth quarter of 2003.

         Subsequent to June 30, 2003, the Company announced its intent to
acquire certain South Texas oil and gas properties for a purchase price, prior
to any purchase price adjustments, of $9.1 million. This acquisition is expected
to close late in the third quarter of 2003.

10. 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.

                                       12


<PAGE>


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

         The following is management's discussion and analysis of certain
significant factors that have affected certain aspects of our financial position
and operating results during the periods included in the accompanying unaudited
condensed consolidated financial statements. This discussion should be read in
conjunction with the accompanying unaudited condensed consolidated financial
statements included elsewhere in this Form 10-Q and with our audited
consolidated financial statements included in our annual report on Form 10-K for
the year ended December 31, 2002.

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 and constitute one
cost center.

         In accordance with the full cost method of accounting, we capitalize 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.

                                       13


<PAGE>
         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 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. Intangible assets with a determinable useful life
will continue to be amortized over that period. The amortization provisions
apply to goodwill and intangible assets acquired after June 30, 2001. The SEC is
currently reviewing the application of the accounting prescribed by these
statements to the oil and natural gas industry. The result may be to require
that mineral use rights, such as leasehold interests, be separately classified
in the balance sheets of oil and natural gas companies. Specifically, these
standards may require that mineral use rights, including proved leaseholds
acquired in a business combination, be classified on the balance sheet as
intangible assets for all leaseholds acquired subsequent to June 30, 2001. We
did not change or reclassify contractual mineral rights included in developed
and unevaluated oil and gas properties on our balance sheet upon adoption of
SFAS No. 141 and 142. We believe the treatment of such mineral rights as
tangible assets under the full cost method of accounting for oil and gas
properties is appropriate. If it is determined that reclassification is
necessary, we would be required to reduce our developed and unevaluated
properties and to instead report intangible mineral rights related to developed
and unevaluated properties. We believe that the provisions of SFAS No. 141 and
142 impact only the balance sheet and any associated footnote disclosures. Any
reclassifications potentially required would not impact our cash flows or
statements of operations, since these costs would continue to be depleted in
accordance with the full cost method of accounting for oil and gas companies.

         We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations"
effective January 1, 2003. The statement required us to record a liability for
the fair value of our dismantlement and abandonment costs, excluding salvage
values. When the liability was initially recorded, we increased the carrying
amount of the related long-lived asset, oil and natural gas properties.
Accretion of the liability is recognized each period and the capitalized cost is
depleted over the useful life of the related asset. Upon settlement of the
liability, we will either settle the obligation for its recorded amount or incur
a gain or loss upon settlement.

         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 accumulated
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 impairment related to the ceiling test
was required during the six-month periods ended June 30, 2003 or 2002.

         In May 2003, the Securities and Exchange Commission ("SEC") issued
Staff Accounting Bulletin ("SAB") No. 103, "Update of Codification of Staff
Accounting Bulletins." SAB No. 103 revises or rescinds portions of the
interpretive guidance included in the codification of staff accounting bulletins
in order to make this interpretive guidance consistent with current
authoritative accounting and auditing guidance and SEC rules and regulations.
The principal revisions relate to the rescission of material no longer necessary
because of private sector developments in U.S. generally accepted accounting
principles, as well as SEC rulemaking. As specifically related to oil and gas,
it requires the inclusion of cash flow hedges in the computation of limitation
on capitalized costs. In the second

                                       14


<PAGE>
quarter of 2003, we adopted these provisions and included the effects of hedge
gains and losses in the ceiling test. Impairment of oil and natural gas
properties is assessed on a quarterly basis in conjunction with our quarterly
filings with the SEC.

         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.

OIL AND NATURAL GAS RESERVES

         There are uncertainties inherent in estimating oil and natural gas
reserve quantities, projecting future production rates and projecting the timing
of future development expenditures. In addition, 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 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
periodically entered into 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 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. 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.

         We 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 accumulated other
comprehensive income (AOCI). The gains and losses on the derivative instrument
that are reported in AOCI will be reclassified to earnings in the period in
which earnings are impacted by the hedged item. We adopted SFAS No. 133
effective on January 1, 2001.

         Upon entering into a derivative contract, we designate the derivative
instruments as a hedge of the variability of cash flow to be received (cash flow
hedge). In accordance with SFAS No. 133, we formally document all relationships
between hedging instruments and hedged items, as well as our risk management
objectives and strategy for undertaking various hedge transactions. We also
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. All of our
derivative instruments at June 30, 2003 were designated and effective as cash
flow hedges. When it is determined that a derivative is not highly effective as
a hedge or that it has ceased to be a highly effective hedge, hedge accounting
would be discontinued prospectively.

         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 included in

                                       15


<PAGE>
AOCI 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
earnings as the hedged production takes place.

         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 or greater than 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
Financial Accounting Standards Board ("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.

         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 and re-priced in May 1999, as well as certain options newly issued
in conjunction with the repricing. No adjustments related to FIN 44 were
required during the first half of 2003.

OVERVIEW

         The following matters had a significant impact on our results of
operations and financial position for the six months ended June 30, 2003:

         Commodity Prices - The average realized price for our production,
before the effects of hedging activity, increased 89% from $2.92 per thousand
cubic feet of gas equivalent (Mcfe) in the first six months of 2002 to $5.51 per
Mcfe for the comparable period this year.

         Hedging Activity - For the six months ended June 30, 2003, we realized
net losses from hedging activities of $(3.3) million, or $(1.01) per Mcfe. For
the six months ended June 30, 2002, hedging activity resulted in a net realized
loss of $(163,800), or $(0.04) per Mcfe.

         Cumulative Effect of Accounting Change - We adopted SFAS No. 143,
"Accounting for Asset Retirement Obligations," effective January 1, 2003. We
used a cumulative effect approach to recognize transition amounts for asset
retirement obligations, asset retirement costs and accumulated accretion and
depletion. The $357,825 cumulative effect of the change in accounting (net of
income taxes of $192,675) was reported in the first quarter of 2003.

                                       16


<PAGE>


RESULTS OF OPERATIONS

         REVENUE AND PRODUCTION

         Oil and natural gas revenue for the second quarter of 2003 increased
24% over the same period in 2002. Oil and natural gas production decreased 8%
from an average of 21.0 MMcfe per day in the second quarter of 2002 to 19.3
MMcfe per day in the same current year period; however, the impact of higher
average realized prices offset the production decrease. Natural gas production
comprised 76% of total production on an equivalent Mcf basis and contributed 81%
of total revenue for the second quarter of 2003. Oil and condensate production
was 9% of total production and contributed 11% of total oil and gas revenue
while natural gas liquids (NGLs) production comprised 15% of total production
and contributed 8% of total oil and gas revenue. In the comparable 2002 period,
natural gas production comprised 64% of total production and contributed 70% of
total revenue. Oil and condensate production was 15% of total production and 17%
of revenue and NGLs production comprised 21% of total production and 13% of
total revenue.

         Oil and natural gas production decreased 16% from an average of 21.7
MMcfe per day in the first half of 2002 to 18.2 MMcfe per day in the same
current year period; however, the impact of higher average realized prices
offset the production decrease. Oil and natural gas revenue for the first half
of 2003 increased 31% over the same period in 2002. Natural gas production
comprised 75% of total production on an equivalent Mcf basis and contributed 79%
of total revenue for the first half of 2003. Oil and condensate production was
10% of total production and contributed 13% of total oil and gas revenue while
natural gas liquids (NGLs) production comprised 15% of total production and
contributed 8% of total oil and gas revenue. In the comparable 2002 period,
natural gas production comprised 74% of total production and contributed 77% of
total revenue. Oil and condensate production was 12% of total production and 14%
of revenue and NGLs production comprised 14% of total production and 9% of total
revenue.

         The following table summarizes volume and price information with
respect to our oil and gas production for the three-month and six-month periods
ended June 30, 2003 and 2002:

<TABLE>
<CAPTION>
                                                         For the Three Months                     For the Six Months
                                                             Ended June 30,                         Ended June 30,
                                                 -----------------------------------     -----------------------------------
                                                                            Increase                               Increase
                                                  2003          2002       (Decrease)     2003          2002      (Decrease)
                                                 -------      -------      ----------    -------       -------    ----------
<S>                                              <C>          <C>          <C>           <C>           <C>        <C>
Gas Volume - MCFGPD (1)                           14,726       13,480         1,246       13,693        16,189        (2,496)
Average Gas Price - per MCF (2)                    $5.70        $3.79        $ 1.91      $  6.10       $  3.03         $3.07
Hedge Loss - per MCF                             $ (0.84)     $ (0.13)       $(0.71)     $ (1.35)      $ (0.06)     $  (1.29)

Oil and Condensate Volume - BPD (3)                  284          513         (229)          303           418          (115)
Average Oil Price - per barrel                   $ 33.70      $ 23.95        $ 9.75      $ 33.72       $ 21.45      $  12.27

Natural Gas Liquids Volume - BPD (3)                 474          737         (263)          455           509           (54)
Average NGL Price - per barrel                   $ 14.28      $ 12.30        $ 1.98      $ 14.58       $ 10.99      $   3.59
</TABLE>

--------------------------------------
(1) MCFGPD - thousand cubic feet of gas per day

(2) Excluding losses from hedging activities

(3) BPD - barrels per day

SECOND QUARTER 2003 COMPARED TO THE SECOND QUARTER 2002

         Natural gas revenue increased 45% from $4.5 million for the second
quarter of 2002 to $6.5 million for the same period in 2003 due to a 33%
increase in the average price received for our natural gas production. The
average natural gas sales price for production in the second quarter of 2003 was
$4.86 compared to $3.66 per Mcf for 2002. This increase in average price
received resulted in increased revenue of approximately $1.6 million (based on
current year production). Included within natural gas revenue for the three
months ended June 30, 2003 was $(1.1)

                                       17


<PAGE>


million representing realized losses from hedging activity that decreased the
effective natural gas sales price by $(0.84) per Mcf. During the second quarter
of 2002, realized losses from hedging activities totaled $(163,800) that reduced
the effective natural gas price by $(0.13) per Mcf. For the three months ended
June 30, 2003, natural gas production increased 9% from 13.5 MMCFGPD in 2002 to
14.7 MMCFGPD in 2003 due primarily to production from new wells drilled
including the O'Connor Ranch East properties and the Gato Creek properties as
well as resumption of production from the Thibodeaux well partially offset by
natural declines in production from existing properties. The increase in
production for the three months ended June 30, 2003 compared to the same period
in 2002 resulted in an increase in revenue of approximately $0.4 million (based
on 2002 second quarter average prices).

         Revenue from sales of oil and condensate decreased 22% from $1.1
million in the second quarter of 2002 to $0.9 million for the comparable 2003
period, due to lower production volumes. Production volumes for oil and
condensate decreased 45% compared to the prior year period of 284 BPD due to
fewer wells with oil and condensate production in operation during the second
quarter of 2003 compared to the second quarter of 2002. Production from new
wells drilled is primarily natural gas and not oil and condensate; therefore,
natural declines in production of oil and condensate was not replaced by these
new wells drilled. The decrease in production of oil and condensate for the
three months ended June 30, 2003 compared to the same period in 2002 resulted in
a decrease in revenue of approximately $0.5 million (based on 2002 second
quarter average prices). The average realized price for oil and condensate in
the second quarter of 2003 was $33.70 per barrel, a 41% increase over the second
quarter 2002 average price of $23.95 per barrel. This increase in the average
realized price received for our oil and condensate production increased revenue
$0.3 million (based on current quarter production).

         Revenue from sales of NGLs decreased from $0.8 million in the second
quarter of 2002 to $0.6 million for the comparable 2003 period due to lower
production. Production volumes for NGLs decreased from 737 BPD in the second
quarter of 2002 to 474 BPD for the comparable period in 2003 due primarily to
our decision to process less gas because of favorable natural gas prices. This
decrease in production resulted in a decrease in quarterly revenue of $294,000
(based on 2002 second quarter average prices). The average realized price for
NGLs in the second quarter of 2003 was $14.28 per barrel compared to $12.30 per
barrel for the same period in 2002. This 16% increase in the average realized
price for our NGLs increased revenue by $85,700 (based on current quarter
production).

SIX MONTHS ENDED JUNE 30, 2003 COMPARED TO THE SIX MONTHS ENDED JUNE 30, 2002

         Natural gas revenue increased 35% from $8.7 million for the first half
of 2002 to approximately $11.8 million for the same period in 2003.
Significantly higher average prices received for our natural gas production more
than offset the decline in production. The average natural gas sales price for
production in the first half of 2003 was $4.75 per Mcf compared to $2.97 per Mcf
for 2002. This increase in average price received resulted in increased revenue
of approximately $4.4 million (based on current year-to-date production).
Included within natural gas revenue for the six months ended June 30, 2003 was
$(3.3) million representing realized losses from hedging activity that decreased
the effective natural gas sales price by $(1.35) per Mcf. During the six months
ended June 30, 2002, realized losses from hedging activities was $(163,800) that
decreased the effective natural gas sales price by $(0.06) per Mcf. For the six
months ended June 30, 2003, natural gas production decreased 15% from 16.2
MMCFGPD in 2002 to 13.7 MMCFGPD in 2003 due primarily to declines in production
from existing properties and the delay in the resumption of production from the
Thibodeaux well, partially offset by production from new wells drilled including
the O'Connor Ranch East properties and the Gato Creek properties. The decrease
in production for the six months ended June 30, 2003 compared to the same period
in 2002 resulted in a decrease in revenue of approximately $1.3 million (based
on 2002 year-to-date average prices).

         Revenue from sales of oil and condensate increased 14% from $1.6
million in the first six months of 2002 to $1.8 million for the comparable 2003
period, due to higher average realized prices. The average realized price for
oil and condensate in the first half of 2003 was $33.72 per barrel, a 57%
increase over the first half of 2002 average price of $21.45 per barrel. This
increase in the average realized price received for our oil and condensate
increased revenue by $672,600 (based on current year-to-date production).
Production volumes for oil and condensate decreased 28% from 418 BPD in the
first half of 2002 to 303 BPD in the 2003 year-to-date period due primarily to
natural declines in production from existing properties. The decrease in
production for the six months ended June

                                       18


<PAGE>
30, 2003 compared to the same period in 2002 resulted in a decrease in revenue
of approximately $447,400 (based on 2002 year-to-date average prices).

         Revenue from sales of NGLs increased from $1.0 million in the first six
months of 2002 to $1.2 million for the comparable 2003 period due to higher
average realized prices. The average realized price for NGLs in the first half
of 2003 was $14.58 per barrel compared to $10.99 per barrel for the same period
in 2002. This 33% increase in the average realized price for our NGLs increased
revenue by $295,500 (based on current year-to-date production). Production
volumes for NGLs decreased from 509 BPD in the first six months of 2002 to 455
BPD for the comparable period in 2003 due to our decision to process less gas
because of favorable natural gas prices. This decrease in production resulted in
a decrease in revenue of $107,200 (based on 2002 year-to-date average prices).

COSTS AND OPERATING EXPENSES

         Lifting costs for the three-month period ended June 30, 2003 totaled
$551,000, 8% lower than the same period in 2002. Lifting costs averaged $0.31
per Mcfe for the three-month period ended June 30, 2003 which was comparable to
the prior year period. For the six-month period ended June 30, 2003, lifting
costs totaled $1.1 million, a 4% decrease compared to the same period in 2002
due primarily to changing the mix of production to newer, lower cost wells.
Lifting costs were $0.35 per Mcfe for the six-month period ended June 30, 2003
compared to $0.30 per Mcfe in the prior year period. This increase in costs per
Mcfe was a result of lower production volumes over fixed expenses.

         Severance and ad valorem taxes for the three months and six months
ended June 30, 2003 totaled $521,900 and $1,041,100, respectively, compared to
$450,200 and $886,000 for the comparable prior year periods. The increase is due
primarily to higher severance taxes paid on the increased revenue reported for
the 2003 periods partially offset by abatements on our Gato Creek properties in
South Texas and the Thibodeaux well in Louisiana. On an equivalent production
basis, severance and ad valorem taxes averaged $0.30 per Mcfe and $0.32 per Mcfe
for the three-month and six-month period ended June 30, 2003 compared to $0.24
per Mcfe and $0.23 per Mcfe for the same periods in 2002. The increase in
expense per Mcfe is due primarily to the higher revenue received while
production was lower over the comparable periods. Severance tax averaged 4.8% of
revenue for the first half of 2003 compared to 6.5% for the same period in 2002
due to the tax abatements discussed above.

         Depletion, depreciation and amortization ("DD&A") expense for the
three-month and six-month periods ended June 30, 2003 totaled $2.8 million and
$5.6 million, respectively. This compares to $2.7 million and $5.5 million in
the same periods of 2002. Full cost DD&A on our oil and natural gas properties
totaled $2.7 million for the second quarter of 2003 compared to $2.5 million for
the same period in 2002. Depletion expense on a unit of production basis for the
three-month period ended June 30, 2003 was $1.56 per Mcfe compared to $1.33 per
Mcfe in the comparable prior year period. For the six months ended June 30, 2003
depletion on our oil and natural gas properties totaled $5.2 million that was
comparable to the same period in 2002. Depletion expense on a unit of production
basis for the six-month period ended June 30, 2003 was $1.59 per Mcfe compared
to $1.32 per Mcfe for the six months ended June 30, 2002. For the six months
ended June 30, 2003 as compared to the prior year period, a 20% increase in the
overall depletion rate increased depletion expense by $871,900 while lower oil
and natural gas production decreased depletion expense by $839,100. The increase
in the depletion rate was primarily due to a significantly higher amortizable
base at June 30, 2003 compared to June 30, 2002. Other DD&A expense totaled
$115,900 and $345,700 for the three-month and six-month periods ended June 30,
2003 compared to the prior period totals of $160,200 and $327,900, respectively.

         General and administrative expenses ("G&A") for the second quarter of
2003 increased 3% from the prior year period to $1.5 million. For the second
quarter of 2003 and 2002, overhead reimbursement fees recorded as a reduction to
G&A totaled $27,500 and $31,000, respectively. Capitalized G&A further reduced
total G&A by $319,000 and $370,400 for the three months ended June 30, 2003 and
2002, respectively. For the six months ended June 30, 2003, G&A was $2.9
million, an increase of 2% compared to the prior year period. For the six months
of 2003 and 2002, overhead reimbursement fees recorded as a reduction to G&A
totaled $56,200 and $63,700, respectively. Capitalized G&A further reduced total
G&A by $621,800 and $740,700 for the six months ended June 30, 2003 and 2002,
respectively. The increase in G&A for both the three months and the six months
ended June 30, 2003 was primarily attributable to higher audit and legal fees,
higher franchise taxes, office moving costs and the

                                       19

<PAGE>
settlement of a lawsuit related to seismic rights in April 2003 for $70,000.
These costs were partially offset by lower salary and benefit costs, lower rent
and parking and lower reserve engineer fees compared to the prior year periods.
G&A on a unit of production basis for the six-month periods ended June 30, 2003
and 2002 was $0.87 per Mcfe and $0.72 per Mcfe, respectively.

         Included in general and administrative expenses were deferred
compensation amortization costs related to restricted stock awards granted
during 2001, 2002 and 2003. For the second quarter of 2003 and 2002, such
amortization totaled $89,800 and $105,400, respectively. For the six months
ended June 30, 2003 and 2002, deferred compensation amortization totaled
$176,400 and $210,600, respectively. Also included in deferred compensation are
charges or credits related to FIN 44, "Accounting for Certain Transactions
involving Stock Compensation." FIN 44 requires, among other things, a non-cash
charge to compensation expense if the price of Edge's 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.
The adjustment is related only to the 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. For the
three-month and six-month periods ended June 30, 2003, no charge or credit was
required to comply with FIN 44. Deferred compensation expense related to FIN 44
was a net credit of $(303) for the three-month and six-month periods ended June
30, 2002.

         For the three months ended June 30, 2003, interest expense totaled
$213,100 on weighted average debt of approximately $21.5 million. Capitalized
interest for the period was $48,100 resulting in net interest expense of
$165,000. For the three months ended June 30, 2002, we capitalized all interest
incurred during the quarter, or $175,600. Our weighted average debt was
approximately $14.3 million in the second quarter of 2002. For the six months
ended June 30, 2003, interest expense totaled $465,400 on weighted average debt
of approximately $21.3 million compared to interest expense of $348,500 on
weighted average debt of $12.7 million in the comparable 2002 period.
Capitalized interest for the six months ended June 30, 2003 and 2002 totaled
$124,000 and $348,500, respectively. Also included in interest expense were
deferred loan costs of $50,700 for the six months ended June 30, 2002. Net
interest expense for the six months ended June 30, 2003 and 2002 was $341,400
and $50,700, respectively. Interest income totaled $3,000 and $5,100 for the
three-month and six-month periods ended June 30, 2003 compared to $3,300 and
$7,100 for the same periods in 2002.

         For the three-month and six-month periods ended June 30, 2003, we
recorded a charge of $845,500 and $1,367,200, respectively, for income taxes at
an effective rate of 35.6% based on the forecast of annual 2003 net income using
assumptions known at that time. An income tax charge of $427,500 and $310,100,
respectively, was recorded for the three-month and six-month periods ended June
30, 2002 representing an estimated effective tax rate of 36%. Such rate was
based on anticipated results for the year ended December 31, 2002 using current
assumptions.

         We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations,"
effective January 1, 2003. We used a cumulative effect approach to recognize
transition amounts for asset retirement obligations, asset retirement costs and
accumulated depreciation. The $357,800 cumulative effect of the change in
accounting (net of income taxes of $192,700) was reported during the first
quarter of 2003.

         For the second quarter of 2003, we realized net income of $1.5 million,
or basic and diluted earnings per share of $0.16. This compares to a net income
for the second quarter of 2002 of $764,000, or basic and diluted earnings per
share of $0.08. Weighted average shares outstanding increased from 9,391,267
shares for the three months ended June 30, 2002 to 9,502,255 shares in the
comparable 2003 period. For the six months ended June 30, 2003, we realized net
income of $2.1 million or basic and diluted earnings per share of $0.22 compared
to net income of $557,100, or $0.06 basic and diluted earnings per share, for
the comparable 2002 period. Weighted average shares outstanding increased from
9,358,253 for the six months ended June 30, 2002 to 9,471,227 for the comparable
2003 period. The increase in shares for both the three-month and six-month
periods was due primarily to the exercise of stock options and the issuance of
common stock related to restricted stock grants.

                                       20


<PAGE>


LIQUIDITY AND CAPITAL RESOURCES

         We had cash and cash equivalents at June 30, 2003 of $3.9 million
consisting primarily of short-term money market investments, as compared to $2.6
million at December 31, 2002. Working capital was $5.3 million as of June 30,
2003, as compared to $3.3 million at December 31, 2002.

         Cash flows provided by operating activities for the six months ended
June 30, 2003 totaled $8.4 million compared to $2.4 million for the six months
ended June 30, 2002. The increase in cash flows provided by operating activities
in 2003 compared to 2002 was due to higher net income in the 2003 period and
lower working capital usage for the six-month period ended June 30, 2003
compared to the same period in 2002.

         Cash used in investing activities totaled approximately $7.6 million
for the six months ended June 30, 2003 compared to $8.6 million in the same
period of 2002. We expended $5.7 million in our drilling operations resulting in
the drilling of 17 gross (7.26 net) wells during the first half of 2003 as
compared to 6 gross (2.17 net) wells during the same period in 2002. Since June
30, 2003, we have drilled two successful gross wells and no gross dry holes.
Currently two gross wells are drilling. In addition to capital expenditures for
drilling operations for the 2003 period, approximately $278,800 was incurred on
currently producing properties and $771,000 was expended on land and seismic
activities. The remaining costs capitalized to oil and natural gas properties
were internal G&A and interest of approximately $745,800 and other furniture and
fixture costs of $187,300. We received proceeds of approximately $55,100 during
the first half of 2003 for the sale of interests in certain oil and gas
properties.

         Cash flows provided by financing activities totaled $553,500 for the
six months ended June 30, 2003 and included $1.7 million in borrowings, $(1.2)
million in repayments of debt and $53,500 in proceeds from the issuance of
stock. For the comparable 2002 period, cash flow provided by financing
activities totaled $6.0 million and included $6.5 million of borrowings from
long-term debt offset by $0.5 million in payments on long-term debt and $47,400
in proceeds from the issuance of stock.

         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 planned
exploration and development program. We do plan to use our credit facility to
fund a portion of the recently announced acquisition of oil and gas properties
in South Texas. That acquisition is expected to close during September of 2003.
In connection with that acquisition, we have been advised that our credit line
is expected to be increased from $26.5 million to $32.0 million upon completion
of that acquisition. Current usage of the credit facility is $21.0 million. The
pending merger with Miller Exploration is a stock for stock transaction that is
expected to increase Edge's resulting liquidity as a result of Miller's expected
positive working capital and relatively low level of debt.

         Generally, we believe that we will be able to generate capital
resources and liquidity sufficient to fund our capital programs and meet
financial obligations as they come due. If necessary, Edge believes it could
access the capital markets to raise additional capital. In the event such
capital resources are not available to us, our capital expenditures may be
curtailed.

CREDIT FACILITY

         During the first half of 2003, we borrowed $1.7 million and made
repayments of $1.2 million under our credit facility (the "Credit Facility") and
as of June 30, 2003, $21.0 million was outstanding under the Credit Facility.
Borrowings under the Credit Facility bear interest at a rate equal to prime plus
0.50% or LIBOR plus 2.75%. The Company chooses which interest rate will be
applied to a specific borrowing. The Credit Facility matures October 6, 2004 and
is secured by substantially all of our assets.

           Effective April 21, 2003, the borrowing base was increased to $26.5
million. The borrowing base will be re-determined again during the second half
of 2003. The borrowing base is not subject to automatic reductions at this time.
We expect our borrowing base to be increased to $32.0 million as a result of the
recently announced

                                       21


<PAGE>
acquisition of oil and gas properties in South Texas and our drilling activities
since the last redetermination. This increase would be effective upon closing of
the acquisition, currently anticipated to be in September 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) 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. EBITDA was part of a negotiated covenant with our lender and is
presented here to define our requirements to comply with that covenant. The
Working Capital ratio requires that the amount of our consolidated current
assets less our consolidated 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 revenue, 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. At June 30, 2003, we were in compliance with
the above-mentioned covenants.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

         In June 2001, 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. Intangible assets with a determinable useful life
will continue to be amortized over that period. The amortization provisions
apply to goodwill and intangible assets acquired after June 30, 2001. The SEC is
currently reviewing the application of the accounting prescribed by these
statements to the oil and natural gas industry. The result may be to require
that mineral use rights, such as leasehold interests, be separately classified
in the balance sheets of oil and natural gas companies. Specifically, these
standards may require that mineral use rights, including proved leaseholds
acquired in a business combination, be classified on the balance sheet as
intangible assets for all leaseholds acquired subsequent to June 30, 2001. We
did not change or reclassify contractual mineral rights included in developed
and unevaluated oil and gas properties on our balance sheet upon adoption of
SFAS No. 141 and 142. We believe the treatment of such mineral rights as
tangible assets under the full cost method of accounting for oil and gas
properties is appropriate. If it is determined that reclassification is
necessary, we would be required to reduce our developed and unevaluated
properties and to instead report intangible mineral rights related to developed
and unevaluated properties. We believe that the provisions of SFAS No. 141 and
142 impact only the balance sheet and any associated footnote disclosures. Any
reclassifications potentially required would not impact our cash flows or
statements of operations, since these costs would continue to be depleted in
accordance with the full cost method of accounting for oil and gas companies.

         In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts
(collectively referred to as derivatives) and for hedging activities under SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities". SFAS
No. 149 is effective for contracts entered into or modified after June 30, 2003.
We have not entered into any applicable contracts since June 30, 2003.

         In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity". SFAS
No. 150 established standards for classification and measurement in the
statement of financial position of certain financial instruments with
characteristics of both liabilities and equity. It requires classification of a
financial instrument that is within its scope as a liability (or an asset in
some circumstances). SFAS 150 is effective for financial instruments entered
into or modified after May 31,

                                       22


<PAGE>
2003, and otherwise is effective at the beginning of the first interim period
beginning after June 15, 2003. This statement is currently not applicable to any
of our financial instruments.

         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 variable interest entity's activities. FIN 46 is
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.

         In May 2003, the Securities and Exchange Commission ("SEC") issued
Staff Accounting Bulletin ("SAB") No. 103, "Update of Codification of Staff
Accounting Bulletins." SAB No. 103 revises or rescinds portions of the
interpretive guidance included in the codification of staff accounting bulletins
in order to make this interpretive guidance consistent with current
authoritative accounting and auditing guidance and SEC rules and regulations.
The principal revisions relate to the rescission of material no longer necessary
because of private sector developments in U.S. generally accepted accounting
principles, as well as SEC rulemaking. As specifically related to oil and gas
producing activities, it requires the inclusion of cash flow hedges in the
computation of limitation on capitalized costs. In the second quarter of 2003,
we adopted these provisions and included the effects of hedge gains and losses
in the ceiling test. Impairment of oil and natural gas properties is assessed on
a quarterly basis in conjunction with our quarterly filings with the SEC.

         We do not expect the adoption of any of the above-mentioned standards
to have a material impact on our future financial condition or results of
operations.

HEDGING ACTIVITIES

         Due to the instability of oil and natural gas prices, we have
periodically entered into 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.

                                       23


<PAGE>


         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. In April 2003, we
entered into a natural gas collar covering 2,000 MMbtu per day for the period
June 1, 2003 to September 30, 2003 with a floor of $5.00 per MMbtu and a ceiling
of $6.50 per MMbtu. At June 30, 2003, the market value of outstanding hedges was
approximately $(2.0) million and is included in current liabilities. See Item 3.
Qualitative and Quantitative Disclosures About Market Risk.

         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. The floor structure provided a minimum realized price for the
protected volume yet preserved any upside in gas prices. The natural gas floor
expired at no additional cost to us.

TAX MATTERS

         At December 31, 2002, we had 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.

                                       24


<PAGE>


ITEM 3. 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 provides a benefit due to downward interest rate movements but
does not limit us to exposure from future increases in interest rates. Based on
the quarter-end June 30, 2003 outstanding borrowings and a floating interest
rate of 3.6%, a 10% change in interest rates would result in an increase or
decrease of interest expense of approximately $72,500 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 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. 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. In April 2003, we
entered into a natural gas collar covering 2,000 MMbtu per day for the period
June 1, 2003 to September 30, 2003 with a floor of $5.00 per MMbtu and a ceiling
of $6.50 per MMbtu. At June 30, 2003, the fair value of the outstanding hedges
was approximately $(2.0) 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
$1.0 million.

ITEM 4. CONTROLS AND PROCEDURES

         In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out
an evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls and
procedures were effective as of June 30, 2003 to provide reasonable assurance
that information required to be disclosed in our reports filed or submitted
under the Exchange Act is recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commission's rules and
forms.

         There has been no change in our internal controls over financial
reporting that occurred during the three months ended June 30, 2003 that has
materially affected, or is reasonably likely to materially affect, our internal
controls over financial reporting.

FORWARD LOOKING STATEMENTS

         The statements contained in all parts of this document, including, but
not limited to, those relating to the timing and effects of the proposed merger
with Miller Exploration Company and our acquisition of properties in South Texas
(including any expectations regarding increases in our liquidity or available
credit), our ability to access the capital markets to raise additional capital,
our drilling plans, our 3-D project portfolio, capital expenditures, future
capabilities, the sufficiency of capital resources and liquidity to support
working capital and capital expenditure requirements, reinvestment of cash
flows, use of NOLs, tax rates, the outcome of litigation, and any other
statements regarding future operations, financial results, business plans,
sources of liquidity and cash needs and other statements that are not historical
facts are forward looking statements. When used in this document, the words
"anticipate," "estimate," "expect," "may," "project," "believe" and similar
expressions are intended to be among the statements that identify forward
looking statements. Such statements involve risks and uncertainties, including,
but not limited to, those relating to the results of and our dependence on our
exploratory drilling activities, the volatility of oil and natural gas prices,
the need to replace reserves depleted by production, operating risks of oil and
natural gas operations, our dependence on key personnel, our reliance on
technological development and

                                       25


<PAGE>


possible obsolescence of the technology currently used by us, the significant
capital requirements of our exploration and development and technology
development programs, the potential impact of government regulations and
liability for environmental matters, results of litigation, our ability to
manage our growth and achieve our business strategy, competition from larger oil
and gas companies, the uncertainty of reserve information and future net revenue
estimates, property acquisition risks and other factors detailed in our Form
10-K and other filings with the Securities and Exchange 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.

PART II - OTHER INFORMATION

ITEM 1 - LEGAL PROCEEDINGS

         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.

<TABLE>
<S>                                                                                                 <C>
ITEM 2 - CHANGES IN SECURITIES AND USE OF PROCEEDS...............................................   None
ITEM 3 - DEFAULTS UPON SENIOR SECURITIES.........................................................   None
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.....................................
</TABLE>

Our stockholders voted on the following matters at the Annual Meeting of
Shareholders on May 7, 2003:

<TABLE>
<CAPTION>
                                                                                                          Broker
                                               For          Against          Withheld       Abstain      Non Votes
                                               ---          -------          --------       -------      ---------
<S>                                          <C>            <C>              <C>            <C>          <C>
(A) Election of Directors:
      Thurmon Andress                        6,977,143         --            1,552,408         --           --
      John W. Elias                          6,986,507         --            1,543,044         --           --
      John Sfondrini                         6,575,616         --            1,953,935         --           --

(B) Approval of the Appointment of
      KPMG LLP as Independent Auditors       8,482,766      14,046               --          32,739         --
</TABLE>

         In addition to the election of the directors indicated above, the
terms of the following directors continued as directors following the meeting:
Vincent S. Andrews, Joseph R. Musolino, Stanley S. Raphael, Robert W. Shower and
David F. Work.

ITEM 5 - OTHER INFORMATION..........................................   None

ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K...........................

(A)      EXHIBITS. The following exhibits are filed as part of this report:

INDEX TO EXHIBITS

<TABLE>
<CAPTION>

Exhibit No.
-----------
<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
</TABLE>

                                       26


<PAGE>


<TABLE>
<S>              <C>
                 (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, as amended (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     --      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).

+3.3     --      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).

+3.4     --      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).

+3.5     --      Second Amendment to Bylaws of the Company on May 7, 2003. (Incorporated by Reference from exhibit 3.4 to the
                 Company's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2003).

+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. (Incorporated by reference from exhibit 4.3 to the Company's Annual Report on Form 10-K for the year
                 ended December 31, 2002).

+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. (Incorporated by reference from exhibit 4.4 to the Company's Annual Report on Form 10-K for the year
                 ended December 31, 2002).

+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
</TABLE>

                                       27


<PAGE>


<TABLE>
<S>              <C>
                 "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    --      Amendment No. 4 dated as of April 21, 2003 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.

+4.12    --      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).

+4.13    --      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. (Incorporated by reference from exhibit 10.2 to the Company's
                 Annual Report on Form 10-K for the year ended December 31, 2002).

+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. (Incorporated by reference from exhibit 10.3 to the Company's
                 Annual Report on Form 10-K for the year ended December 31, 2002).

+10.5    --      Letter Agreement between Edge Petroleum Corporation and Essex Royalty Limited Partnership, dated as of July 30,
                 2002. (Incorporated by reference from exhibit 10.4 to the Company's Annual Report on Form 10-K for the year ended
                 December 31, 2002).
</TABLE>

                                       28


<PAGE>


<TABLE>
<S>              <C>
+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.
                 (Incorporated by reference from exhibit 10.8 to the Company's Annual Report on Form 10-K for the year ended
                 December 31, 2002).

+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   --      Severance Agreements by and between Edge Petroleum Corporation and the Officers of the Company named therein
                 (Incorporated by reference from Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarterly
                 period ended September 30, 1999).

+10.13   --      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).

+10.14   --      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)).

+10.15   --      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)).

*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).
</TABLE>

* Filed herewith.

+ Incorporated by reference as indicated.

                                       29


<PAGE>


(B) Reports on Form 8-K

         The Company filed a Current Report on Form 8-K on April 15, 2003
(information furnished not filed) announcing the issuance of a press release
reporting 2003 first quarter operations update and attaching a copy of the press
release as an exhibit.

         The Company filed a Current Report on Form 8-K on May 7, 2003
(information furnished not filed) announcing the issuance of a press release
announcing First Quarter Financial Results and attaching a copy of the press
release as an exhibit.

         The Company filed a Current Report on Form 8-K on May 29, 2003
(information furnished not filed) announcing the issuance of a press release
announcing a merger with Miller Exploration Company and attaching a copy of the
press release as an exhibit.

          The Company filed a Current Report on Form 8-K on June 3, 2003 under
Item 5 "Other Events" announcing that the Company and Miller Exploration Company
had entered into a definitive merger agreement pursuant to which Edge would
acquire Miller in a stock for stock merger.

                                       30


<PAGE>


                                   SIGNATURES

         Pursuant to the requirements 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,
                                                     A DELAWARE CORPORATION
                                                     (REGISTRANT)

Date 8/14/2003                         /s/ John W. Elias
                                     -------------------------------------------
                                                John W. Elias
                                           Chief Executive Officer and
                                              Chairman of the Board

Date 8/14/2003                         /s/ Michael G. Long
                                     -------------------------------------------
                                                Michael G. Long
                                           Senior Vice President and
                                      Chief Financial and Accounting Officer

                                       31


<PAGE>


                                INDEX TO EXHIBITS

<TABLE>
<CAPTION>
Exhibit No.
--------------
<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, as amended (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     --      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).

+3.3     --      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).

+3.4     --      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).

+3.5     --      Second Amendment to Bylaws of the Company on May 7, 2003. (Incorporated by Reference from exhibit 3.4 to the
                 Company's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2003).

+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. (Incorporated by reference from exhibit 4.3 to the Company's Annual Report on Form 10-K for the year
                 ended December 31, 2002).

+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. (Incorporated by reference from exhibit 4.4 to the Company's Annual Report on Form 10-K for the year
                 ended December 31, 2002).
</TABLE>

                                       32


<PAGE>

<TABLE>
<S>              <C>
+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    --      Amendment No. 4 dated as of April 21, 2003 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.

+4.12    --      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).

+4.13    --      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. (Incorporated by reference from exhibit 10.2 to the Company's
                 Annual Report on Form 10-K for the year ended December 31, 2002).
</TABLE>

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<TABLE>
<S>              <C>
+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. (Incorporated by reference from exhibit 10.3 to the Company's
                 Annual Report on Form 10-K for the year ended December 31, 2002).

+10.5    --      Letter Agreement between Edge Petroleum Corporation and Essex Royalty Limited Partnership, dated as of July 30,
                 2002. (Incorporated by reference from exhibit 10.4 to the Company's Annual Report on Form 10-K for the year ended
                 December 31, 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.
                 (Incorporated by reference from exhibit 10.8 to the Company's Annual Report on Form 10-K for the year ended
                 December 31, 2002).

+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   --      Severance Agreements by and between Edge Petroleum Corporation and the Officers of the Company named therein
                 (Incorporated by reference from Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarterly
                 period ended September 30, 1999).

+10.13   --      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).

+10.14   --      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)).

+10.15   --      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)).

*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).
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                                       34


<PAGE>
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<S>              <C>
*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).
</TABLE>

* Filed herewith.

+ Incorporated by reference as indicated.

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