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

                                    FORM 10-Q

              [X] QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934

                  For the quarterly period ended MARCH 31, 2002

                                       OR

             [ ] TRANSITION REPORT UNDER 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.)


                              Texaco Heritage Plaza
                             1111 Bagby, Suite 2100
                              Houston, Texas 77002
                    (Address of principal executive offices)

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

        Class                           Outstanding at May 10, 2002
        -----                           ---------------------------
     Common Stock                                 9,390,615



<PAGE>

                          PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EDGE PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
------------------------------------------------------------------------------
<TABLE>
<CAPTION>

                                                                                           March 31,        December 31, 2001
                                                                                              2002
                                                                                       -----------------    ----------------
                                                                                           (Unaudited)
<S>                                                                                    <C>                  <C>
ASSETS
CURRENT ASSETS:
  Cash and cash equivalents                                                            $        307,264     $       793,287
  Accounts receivable, trade, net of allowance of $525,248 at March 31, 2002 and
    December 31, 2001, respectively                                                           4,623,897           5,184,522
  Accounts receivable, joint interest owners, net of allowance of $163,000 at
    March 31, 2002 and December 31, 2001, respectively                                          425,580             322,001
  Accounts receivable, related parties                                                           66,337                  --
  Current deferred tax asset                                                                    624,258             584,580
  Other current assets                                                                          705,180             402,566
                                                                                       ----------------     ---------------
    Total current assets                                                                      6,752,516           7,286,956

PROPERTY AND EQUIPMENT, Net - full cost method of accounting for oil and natural
  gas properties                                                                             66,905,756          66,853,094
DEFERRED TAX ASSET                                                                              673,704             556,317
OTHER ASSETS                                                                                      7,788               7,788
                                                                                       ----------------     ---------------
TOTAL ASSETS                                                                           $     74,339,764     $    74,704,155
                                                                                       ================     ===============
LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES:
  Accounts payable, trade                                                              $      2,047,929     $     1,412,451
  Accrued liabilities                                                                         2,782,064           5,192,440
  Accrued interest payable                                                                       80,676                  --
                                                                                       ----------------     ---------------
    Total current liabilities                                                                 4,910,669           6,604,891

LONG-TERM DEBT                                                                               11,500,000          10,000,000
                                                                                       ----------------     ---------------
    Total liabilities                                                                        16,410,669          16,604,891
                                                                                       ----------------     ---------------
COMMITMENTS AND CONTINGENCIES

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; 9,351,215 shares
     and 9,305,079 shares issued and outstanding at March 31, 2002 and December
     31, 2001, respectively                                                                      93,513              93,051
  Additional paid-in capital                                                                 56,246,267          56,139,451
  Retained earnings                                                                           1,659,854           1,866,762
  Accumulated other comprehensive loss                                                          (70,539)                 --
                                                                                       ----------------     ---------------
    Total stockholders' equity                                                               57,929,095          58,099,264
                                                                                       ----------------     ---------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                                             $     74,339,764     $    74,704,155
                                                                                       ================     ===============
</TABLE>


          See accompanying notes to consolidated financial statements.

                                       2
<PAGE>



EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
------------------------------------------------------------------------------
<TABLE>
<CAPTION>

                                                                                              Three Months Ended
                                                                                                  March 31,
                                                                                     -------------------------------------
                                                                                          2002                 2001
                                                                                     ----------------    -----------------
<S>                                                                                  <C>                 <C>
OIL AND NATURAL GAS REVENUE                                                          $     4,907,597     $     11,523,071

OPERATING EXPENSES:
  Lifting costs                                                                              596,245              607,910
  Severance and ad valorem taxes                                                             435,722              914,327
  Depletion, depreciation and amortization                                                 2,832,163            1,998,659
  General and administrative expenses                                                      1,241,418            1,228,341
  Deferred compensation expense (benefit)                                                    104,878             (709,157)
                                                                                     ---------------     ----------------
    Total operating expenses                                                               5,210,426            4,040,080
                                                                                     ---------------     ----------------
OPERATING INCOME (LOSS)                                                                    (302,829)            7,482,991

OTHER INCOME AND EXPENSE:
  Interest income                                                                              3,878               22,901
  Interest expense, net                                                                      (25,344)             (33,705)
                                                                                     ---------------     ----------------
INCOME (LOSS) BEFORE INCOME TAXES                                                           (324,295)           7,472,187

INCOME TAX BENEFIT (EXPENSE)                                                                 117,387           (1,021,671)
                                                                                     ---------------     ----------------
NET INCOME  (LOSS)                                                                          (206,908)           6,450,516
OTHER COMPREHENSIVE INCOME (LOSS):
  Transition adjustment                                                                            --          (1,137,221)
  Realization of hedging losses                                                                    --             874,790
  Change in valuation of hedging instruments                                                 (70,539)             200,101
                                                                                     ---------------     ----------------
COMPREHENSIVE INCOME (LOSS)                                                          $      (277,447)    $      6,388,186
                                                                                     ===============     ================
BASIC EARNINGS (LOSS) PER SHARE                                                      $         (0.02)    $           0.70
                                                                                     ===============     ================
DILUTED EARNINGS (LOSS) PER SHARE                                                    $         (0.02)    $           0.67
                                                                                     ===============     ================
BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING                                 9,324,875            9,223,976
                                                                                     ===============     ================
DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES
   OUTSTANDING                                                                             9,324,875            9,656,937
                                                                                     ===============     ================
</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, JANUARY 1, 2002      9,305,079       $ 93,051    $ 56,139,451     $ 1,866,762      $      --         $ 58,099,264

Exercise of stock
  options                           800              8           2,392              --             --                2,400

Issuance of stock                45,336            454            (454)             --             --                   --

Deferred compensation
  expense                            --             --         104,878             --               --             104,878

Change in valuation of
  hedging instruments,
  net of tax of $39,678              --             --              --             --          (70,539)            (70,539)

Net income (loss)                    --             --              --       (206,908)             --             (206,908)
                             ----------     ----------   -------------     ----------       ----------       -------------

BALANCE, MARCH 31, 2002       9,351,215     $   93,513   $  56,246,267     $1,659,854       $  (70,539)      $  57,929,095
                             ==========     ==========   =============     ==========       ==========       =============
</TABLE>






          See accompanying notes to consolidated financial statements.

                                       4
<PAGE>



EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
------------------------------------------------------------------------------

<TABLE>
<CAPTION>
                                                                                               Three Months Ended March 31,
                                                                                          ----------------------------------------
                                                                                                2002                  2001
                                                                                          ------------------    ------------------
<S>                                                                                       <C>                   <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)                                                                            $     (206,908)       $    6,450,516
Adjustments to reconcile net income (loss) to net cash provided by operating
   activities:
    Deferred income taxes                                                                          (117,387)            1,021,671
    Depletion, depreciation and amortization                                                      2,832,163             1,998,659
    Amortization of deferred loan costs                                                              25,344                25,811
    Deferred loss from derivative activity                                                         (110,217)              (62,330)
    Deferred compensation                                                                           104,878              (709,157)
Changes in assets and liabilities:
    Decrease in accounts receivable, trade                                                          560,625             1,796,072
    Increase in accounts receivable, joint interest owners                                         (103,579)              (70,323)
    Increase in accounts receivable, related parties                                                (66,337)             (122,105)
    Increase in other assets                                                                       (327,958)             (397,479)
    Increase (decrease) in accounts payable, trade                                                  635,478              (947,323)
    Decrease in accrued liabilities                                                              (2,410,376)             (697,523)
    Increase (decrease) in accrued interest payable                                                  80,676               (50,385)
                                                                                             --------------        --------------
      Net cash provided by operating activities                                                     896,402             8,236,104
                                                                                             --------------        --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Oil and natural gas property and equipment purchases                                           (2,884,825)           (2,588,605)
                                                                                             --------------        --------------
      Net cash used in investing activities                                                      (2,884,825)           (2,588,605)
                                                                                             --------------        --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Borrowings from long-term debt                                                                  1,500,000             1,000,000
  Payments of long-term debt                                                                             --            (4,000,000)
  Net proceeds from issuance of common stock                                                          2,400               174,076
  Other                                                                                                  --                (7,669)
                                                                                             --------------        --------------
      Net cash provided by (used in) financing activities                                         1,502,400            (2,833,593)
                                                                                             --------------        --------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                                               (486,023)            2,813,906

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD                                                      793,287               247,981
                                                                                             --------------        --------------

CASH AND CASH EQUIVALENTS, END OF PERIOD                                                     $      307,264        $    3,061,887
                                                                                             ==============        ==============
</TABLE>




          See accompanying notes to consolidated financial statements.


                                       5
<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, 2001.

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

ACCOUNTING PRONOUNCEMENTS

    DERIVATIVES - We adopted Statement of Financial Accounting Standards No.
133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133")
effective January 1, 2001. The statement, as amended, 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 fair value of the derivative instrument will
generally be reported in Other Comprehensive Income ("OCI"). The gains and
losses on the derivative instrument that are reported in OCI will be
reclassified to earnings in the period in which earnings are impacted by the
hedged item.

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

      During the first quarter of 2001, we adopted the new hedging requirements.
As a result, we recorded the fair value of our natural gas hedge derivative
instrument of approximately ($1.1) million as a liability on our balance sheet
as part of the transition adjustment related to our adoption of SFAS 133. The
offset to this balance sheet adjustment was a decrease to OCI. In early January
2001, we closed out of our hedge obligation for the period from February 1, 2001
to December 31, 2001. As a result, we recorded a loss on the January 2001 hedge
of $389,360 and amortized the close out cost of $547,760 based on the forward
pricing curve at the time of the close out in accordance with SFAS 133. Included
in earnings for the first quarter of 2001 was a charge of $874,790 representing
the loss in January 2001 and the amortized portion of the close out cost as of
March 31, 2001. The unamortized balance of the close out cost of $62,330 was
included in stockholders' equity as accumulated other comprehensive loss. We
account for our natural gas and crude oil hedge derivative instruments as cash
flow hedges, as defined in SFAS 133.



                                       6
<PAGE>

2.  LONG TERM DEBT

    During the first quarter of 2002, we borrowed $1.5 million under our credit
facility (the "Credit Facility") and as of March 31, 2002, $11.5 million was
outstanding. Borrowings under the Credit Facility bear interest at a rate equal
to prime plus 0.50% or LIBOR plus 2.75%. The Credit Facility matures October 6,
2003 and is secured by substantially all of our assets.

    In January 2002, the borrowing base was increased to $18 million. The
borrowing base will be re-determined again during the second quarter of 2002.
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. 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 .40 to 1.0. At March 31,
2002, we were in compliance with the above-mentioned covenants.


3.  EARNINGS PER SHARE

    We account for earnings per share in accordance with Statement of Financial
Accounting Standards No. 128 - "Earnings per Share," ("SFAS No. 128") 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.

    During the three months ended March 31, 2002, we reported a net loss, thus
the effects of stock options, restricted stock granted but to be issued upon
vesting and warrants were antidilutive. 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 months ended March
31, 2001:

<TABLE>
<CAPTION>

                                                     Three Months Ended March 31, 2001
                                              ------------------------------------------------
                                                 Income             Shares         Per Share
                                               (Numerator)      (Denominator)        Amount
                                              --------------   -----------------   -----------
<S>                                           <C>                     <C>          <C>
BASIC EPS
Income available to common stockholders       $   6,450,516           9,223,976    $     0.70
Effect of dilutive securities:
   Restricted stock                                      --             131,572         (0.01)
   Common stock options                                  --             301,389         (0.02)
                                              -------------        ------------    ----------
DILUTED EPS
Income available to common stockholders       $   6,450,516           9,656,937    $     0.67
                                              =============        ============    ==========
</TABLE>
                                       7
<PAGE>


4.   INCOME TAXES

     We account for income taxes under the provisions of Statement of Financial
Accounting Standards No. 109 - "Accounting for Income Taxes," ("SFAS No. 109")
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.

     During 2001, we determined that it was more likely than not that future
taxable income would be sufficient to realize our recorded tax assets and
accordingly, the remaining valuation allowance was reversed. We currently
estimate that our effective tax rate for the year ending December 31, 2002 will
be approximately 36%. As a result of incurring a loss in the first quarter of
2002, an income tax benefit of $117,387 was recorded. For the three months ended
March 31, 2001, a provision for income taxes of approximately $1.0 million was
reported.


5.   EQUITY

     We account for Stock Based Compensation in accordance with Statement of
Financial Accounting Standards No. 123 - "Accounting for Stock Based
Compensation," ("SFAS No. 123"). Under SFAS No. 123, we are permitted to either
record expense for stock options and other employee compensation plans based on
their fair value at the date of grant or to continue to apply our current
accounting policy under Accounting Principles Board Opinion No. 25 ("APB No.
25") and recognize compensation expense, if any, based on the intrinsic value of
the equity instrument at the measurement date. We have elected to continue
following APB No. 25.

     Deferred compensation cost reported in accordance with FASB Interpretation
No. (FIN) 44, Accounting for Certain Transactions involving Stock Compensation
was a credit of $303 for the three months ended March 31, 2002 compared to a
credit of $755,372 in the comparable prior year period. FIN 44 requires, among
other things, a non-cash charge to compensation expense if the price of our
common stock on the last trading day of a reporting period is greater that 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, to report under this rule as a result of non-qualified stock
options granted to employees and directors in prior years and re-priced in May
of 1999, as well as certain options newly issued in conjunction with the
repricing as discussed above.

     During the first quarter of 2001, we purchased options exercisable for
133,645 shares of common stock from a former employee of ours at a cost of
$100,000, all of which represents compensation expense.


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

     We consider all highly liquid debt instruments purchased with an original
maturity of three months or less to be cash equivalents. A summary of non-cash
investing and financing activities for the three months ended March 31, 2002 and
2001 is presented below:

     We issued 45,336 shares of common stock during the first quarter of 2002
with an average fair market value of $174,575 at the time of grant. These shares
represent one-third of the shares subject to restricted stock grants made
effective in January 2001 and March 2000.

     We issued 42,103 shares of common stock during the first quarter of 2001
with a fair market value of $126,300 at the time of grant. These shares
represent one-third of the shares subject to a restricted stock grant made
effective March 2000.


                                       8
<PAGE>

Supplemental Disclosure of Cash Flow Information

<TABLE>
<CAPTION>
                                                              For the Three Months Ended March
                                                                             31,
                                                              ----------------------------------
                                                                  2002                2001
                                                              --------------      --------------
<S>                                                           <C>                 <C>
Cash paid during the period for:
    Interest, net of amounts capitalized                      $          --       $      12,226
    Estimated alternative minimum tax payments                           --              75,000
</TABLE>

      Interest paid for the three months ended March 31, 2002 and 2001 excludes
amounts capitalized of $172,859 and $24,402, respectively.


7.    HEDGING ACTIVITIES

      Due to the instability of oil and natural gas prices, we enter into, from
time to time, price risk management transactions (e.g., swaps, collars and
floors) for a portion of our oil and natural gas production to achieve a more
predictable cash flow, as well as to reduce exposure from price fluctuations.
While the use of these arrangements may limit the benefit to us of increases in
the price of oil and natural gas it may also limit the downside risk of 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 limit potential
gains from future increases in prices. We account for these transactions as
hedging activities and, accordingly, gains and losses are included in oil and
natural gas revenue during the period the hedged production occurs.

      No hedges were in place on production for the three months ended March 31,
2002. The following was the impact on oil and natural gas revenue from hedging
activities for the three months ended March 31, 2001:

<TABLE>
<CAPTION>

                                                                     Loss for the
                                                                     Three Months
                                          Price        MMBtu             Ended
  Hedge           Effective Dates           Per        Volumes         March 31,
   Type          Beg.        Ending        MMBtu       Per Day           2001
------------   ---------    ---------    ---------    ----------   ---------------
<S>              <C>         <C>           <C>            <C>          <C>
Natural
  Gas            1/1/01      1/31/01       $4.50 -        4,000        $(389,360)
  Collar                                   $6.70
Amortization of loss from close out of hedge                            (485,430)
                                                                       ---------
Total                                                                  $(874,790)
                                                                       =========
</TABLE>


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

      In 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 provides a minimum realized price for the protected volume
yet preserves any upside in gas prices. At March 31, 2002, the fair value of the
hedge was $53,583.

      Included within oil and natural gas revenue for the three months ended
March 31, 2001 was $(874,790) representing net losses from hedging activity.
During December 2000, we entered into a natural gas collar covering 4,000 MMbtu
per day for the period January 1, 2001 to December 31, 2001 with a floor of
$4.50 per MMBtu and a ceiling of $6.70 per MMbtu. For the month of January we
realized a loss on hedging activity of $(389,360). On January 3, 2001, we closed
out the hedge for the period February 1, 2001 to December 31, 2001 at a cost of
$547,760. In accordance with SFAS 133, this amount is amortized over the period
of the hedge based on the forward pricing curve at the time the hedge was closed
out. We recorded amortization of $(485,430) in oil and natural gas revenue for
the close out cost of the hedge during the first quarter of 2001 with the
balance of $62,330 to be amortized over the remainder of the year. No hedges
were in place at March 31, 2001.


                                       9
<PAGE>


8.       COMMITMENTS AND CONTINGENCIES

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

         In October 2001, the Company was sued by certain mineral owners in its
Mew lease, upon which the Company and its partners drilled and completed the Mew
No. 1 well in the Brandon Area, Duval County, Texas. The suit names the Company,
Santos USA and Mark Smith, an independent landman, as Defendants, and is filed
in the 229th Judicial District Court of Duval County, Texas. The suit seeks a
declaratory judgment to set aside certain quitclaim deeds between the Mew
lessors that were intended to result in a partition of the mineral estate
between the various members of the Mew family in the land where the well is
located and other lands. The pleadings allege failure of consideration, fraud,
failure to consummate the partition, bad faith trespass and conversion. As part
of the leasing effort for the prospect, some members of the Mew family had
sought to partition their minerals under the tracts where they owned the surface
in full. The Mew heirs, from whom the Company acquired leases, could lose a
portion of their mineral interest if the quitclaim deeds are set aside. Were
this to happen, it could have the effect of voiding the Company's leases as to
an undivided one-third of the unit acreage for the Mew well and the Mew lease.
Plaintiffs seek unspecified actual and exemplary damages against the Company and
Santos arising out of the alleged fraud committed by the Company and Mark Smith.
They also seek damages from Santos for the value of the oil and natural gas
produced and saved from the Mew well, or alternatively, for the value of the oil
and natural gas produced less the cost of drilling, completing and operating the
well. The Company has a 12.5% working interest in the well. To date, the Mew
well has produced $5.7 million in net revenue and has cost $3.6 million to
drill, complete and operate. Estimated gross proved reserves are 111.6 MBbls and
4.6 Bcf. The Company has filed an answer in the case. Santos has filed a plea of
abatement asking that the case be dismissed for failure to join necessary and
indispensable parties. At this point, it is not possible to determine the
ultimate outcome of this litigation or the exposure, if any, the Company may
have.

           In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in the N. LaCopita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil has filed
a counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. ExxonMobil seeks
unspecified damages for the lost profits on the sale of the hydrocarbons from
this property, and for a determination of whether the Company and the other
working interest owners were in good faith or bad faith in trespassing on this
lease. If a determination of bad faith is made, the parties will not be able to
recover their costs of developing this property from the revenues therefrom.
While there is always a risk in the outcome of the litigation, the Company
believes there is no question that it acted in good faith and intends to
vigorously defend its position. The Company, along with GMT and the other
partners, are attempting to negotiate a settlement with ExxonMobil that would
allow GMT et al (including the Company) to participate for their respective
shares of a 23% working interest in the Neblett unit, and would allow for the
recovery of well costs. If the case cannot be settled and the title issue is
decided unfavorably, the Company believes that it will ultimately be able to
recover its costs as a good faith trespasser. Due to the uncertainty of the
final outcome, the Company has ceased to record revenue from the properties as
of August 1, 2001, which net to the Company averaged approximately 1.4 Mmcfe/d
of production at the time the well was shut-in. In addition, the Company removed
associated reserves of 1.4 Bcfe from its total proved reserves. The Company
believes this potential loss is not material to its financial condition or
results of operations.

                                       10

<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, 2001.


      OVERVIEW

      The following matters had a significant impact on our results of
operations and financial position for the three months ended March 31, 2002:

      Commodity Prices - The average realized price for our production, before
the effects of hedging activity, decreased 65% from $7.00 per thousand cubic
feet of gas equivalent (Mcfe) in the first three months of 2001 to $2.42 per
Mcfe for the comparable period this year. No hedging was in place on production
for the first quarter of 2002, however, hedging activity for the three months
ended March 31, 2001 resulted in a net loss of $874,790, or $0.49 per Mcfe.

      Debt - As of March 31, 2002, borrowings under our Credit Facility totaled
$11.5 million compared to no borrowings at March 31, 2001. Proceeds from our
borrowings under the Credit Facility were used to fund the December 2001
property acquisition, the cash payment Of $2.5 million to BNP for the settlement
of litigation in 2001 and first quarter 2002 capital expenditures.


      RESULTS OF OPERATIONS

REVENUE AND PRODUCTION

      Oil and natural gas production increased 14% from an average of 19,684
MMcfe per day in the first quarter of 2001 to 22,529 MMcfe per day in the same
current year period; however, the impact of lower average realized prices offset
the favorable production increase. Oil and natural gas revenue for the first
quarter of 2002 decreased 57% over the same period in 2001. Natural gas
production comprised 84% of total production on an equivalent Mcf basis and
contributed 86% of total revenue for the first quarter of 2002. Oil and
condensate production was 9% of total production and contributed 10% of total
oil and gas revenue while natural gas liquids (NGLs) production comprised 7% of
total production and contributed 4% of total oil and gas revenue. In the
comparable 2001 period, natural gas production comprised 91% of total production
and contributed 93% of total revenue. Oil and condensate production was 8% of
total production and 6% of revenue and NGLs production comprised 1% of total
production and total revenue.

      The following table summarizes volume and price information with respect
to our oil and gas production for the quarters ended March 31, 2002 and 2001:

                                       11
<PAGE>


<TABLE>
<CAPTION>

                                                                     For the Three Months
                                                                       Ended March 31,
                                                            ---------------------------------------
                                                                                        Increase
                                                              2002         2001        (Decrease)
                                                            ---------    ---------    -------------
<S>                                                            <C>          <C>             <C>
Gas Volume - MCFGPD (1)                                       18,928       17,956              972
Average Gas Price - per MCF                                    $2.47        $7.23           $(4.76)
Hedge Loss - per MCF                                              --       $(0.54)           $0.54

Oil and Condensate Volume - BPD (2)                              322          252               70
Average Oil Price - per barrel                                $17.41       $28.71          $(11.30)

Natural Gas Liquids Volume - BPD (2)                             278           36              242
Average NGL Price - per barrel                                 $7.50       $21.43          $(13.93)

</TABLE>
(1) MCFGPD - thousand cubic feet of gas per day
(2) BPD - barrels per day


FIRST QUARTER 2002 COMPARED TO THE FIRST QUARTER 2001

      Natural gas sales revenue decreased 61%, from $10.8 million for the first
quarter of 2001 to approximately $4.2 million for the same period in 2002. The
impact of an increase in production and no hedge losses in the first quarter of
2002 was more than offset by a significant decrease in the average realized
price received for our natural gas production. Production volumes for natural
gas for the three months ended March 31, 2002 increased 5% from 17,956 MCFGPD
for the first quarter of 2001 to 18,928 MCFGPD for the comparable period in
2002. This increase in natural gas production during the first quarter of 2002
increased revenue by $618,700 (based on 2001 first quarter average prices). The
increase was due to production from 17 gross (6.744 net) new successful
exploratory and development wells drilled and completed since March 31, 2001.
The average realized price for natural gas production, excluding the effect of
hedging activity, was $2.47 per Mcf for the first quarter of 2002, a decrease of
66% compared to the 2001 first quarter average price of $7.23 per Mcf. This
decrease in average prices impacted revenue by approximately $8.0 million (based
on current quarter production). Included within natural gas revenue for the
three months ended March 31, 2001 was $(874,790) representing losses from
hedging activities. These losses decreased the effective natural gas price by
$(0.54) per Mcf for the first quarter of 2001. There were no hedging activities
in the first quarter of 2002.

      Revenue from sales of oil and condensate decreased 23% from $651,851 in
the first quarter of 2001 to $504,534 for the comparable 2002 period. The impact
of a 28% increase in production was offset by a 39% decrease in average realized
prices. Production volumes for oil and condensate increased from 252 BPD in the
first quarter of 2001 to 322 BPD for the comparable period in 2002. This
increase in production favorably impacted quarterly revenue $179,900 (based on
2001 first quarter average prices). The average realized price for oil and
condensate in the first quarter of 2002 was $17.41 per barrel, compared to
$28.71 per barrel for the same period in 2001. This decrease in the average
realized price received for our oil and condensate decreased revenue $327,200
(based on current quarter production).


      Revenue from sales of NGLs increased significantly from $68,877 in the
first quarter of 2001 to $187,720 for the comparable 2002 period due to higher
production. Production volumes for NGLs increased from 36 BPD in the first
quarter of 2001 to 278 BPD for the comparable period in 2002. Due to lower
natural gas prices, we elected to process much of our gas during the first
quarter of 2002 compared to high prices in the first quarter of 2001 that
resulted in our not processing much of our gas. This increase in production
favorably impacted quarterly revenue $467,700 (based on 2001 first quarter
average prices). The average realized price for NGLs in the first quarter of
2002 was $7.50 per barrel compared to $21.43 per barrel for the same period in
2001. This decrease in the average realized price for our NGLs decreased revenue
by $348,900 (based on current quarter production).

                                       12
<PAGE>


    COSTS AND OPERATING EXPENSES

      Lifting costs for the three-month period ended March 31, 2002 totaled
$596,245, a 2% decrease compared to the same period in 2001. Lifting costs were
$0.29 per Mcfe for the three-month period ended March 31, 2002 compared to $0.34
per Mcfe in the prior year period. Prior year expense was impacted by high
saltwater disposal costs that drove the Mcfe cost higher by approximately $0.02
per Mcfe. In addition, properties added in the current year, including the
Ibarra, LaJolla Parr, Mire and Robertson wells, had significant production on
relatively low costs in the first quarter of 2002 but were not producing in the
prior year period.

      Severance and ad valorem taxes for the three months ended March 31, 2002
decreased 52% from $914,327 in the prior year period to $435,722 in 2002, due
primarily to lower severance taxes paid on the significantly less revenue during
the first quarter of 2002. Severance and ad valorem taxes were $0.21 per Mcfe
and $0.51 per Mcfe for the three-month periods ended March 31, 2002 and 2001,
respectively. The decrease in expense per Mcfe is due directly to the
calculation of tax on the revenue amount that was significantly higher in the
prior year period while production increased from 2001 to 2002. Severance tax
averaged 7.3% of revenue for the first quarter of 2002 compared to 7.1% for the
same period in 2001.

      Depletion, depreciation and amortization expense ("DD&A") expense for the
first quarter of 2002 totaled $2.8 million compared to $2.0 million in the first
quarter of 2001. Full cost DD&A on our oil and natural gas properties totaled
$2.7 million for the first quarter of 2002 compared to $1.8 million for the same
period in 2001. Depletion expense on a unit of production basis for the
three-month periods ended March 31, 2002 and 2001 was $1.31 per Mcfe and $1.03
per Mcfe, respectively. For the first quarter of 2002 as compared to the prior
year period, a 27% increase in the overall depletion rate increased depletion
expense by $573,500 while higher oil and natural gas production increased
depletion expense by $264,000. The increase in the depletion rate was primarily
due to a higher amortizable base at March 31, 2002 compared to March 31, 2001.
Other DD&A expense of $167,635 for the three-month period ended March 31, 2002
was slightly lower than the comparable prior period total of $171,643.

      General and administrative expenses ("G&A") for the first quarter of 2002,
excluding deferred compensation expense related to restricted stock and FIN 44
requirements, increased 1% to $1,241,418, as compared to $1,228,341 for the
three months ended March 31, 2001. The increase in G&A was primarily
attributable to higher salaries and benefits and higher professional services
for the first quarter of 2002 compared to the same period in 2001, offset by
compensation expense of $100,000 recorded in the first quarter of 2001 related
to the purchase of options from a former employee. For the first quarter of 2002
and 2001, overhead reimbursement fees recorded as a reduction to G&A totaled
$32,800 and $5,300, respectively. Capitalized G&A further reduced total G&A by
$370,400 and $411,000 for the three months ended March 31, 2002 and 2001,
respectively. G&A on a unit of production basis for the three-month periods
ended March 31, 2002 and 2001 was $0.61 per Mcfe and $0.69 per Mcfe ($0.64 per
Mcfe excluding the compensation expense), respectively.

      Deferred compensation expense for the first quarter of 2002 was a charge
of $104,878, before income taxes, that included $105,181 for the amortization of
expense related to restricted stock offset by a credit of $(303) for options
with revised terms. For the first quarter of 2001 deferred compensation expense
was a net credit of $(709,157), or $(0.08) per share. A non-cash credit to
deferred compensation expense of $(755,372), or $(0.08) per share before income
taxes or $(649,620), or $(0.07) per share after income taxes, was recorded for
the three months ended March 31, 2001 related to FASB Interpretation No. ("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. At March 31, 2001, the price of Edge's common
stock had declined from the price at December 31, 2000 resulting in the credit
to deferred compensation expense for the three months ended March 31, 2001.
Partially offsetting this credit was the amortization of compensation expense of
$46,215 related to restricted stock grants.


                                       13
<PAGE>


      For the three months ended March 31, 2002, we capitalized all interest
incurred during the quarter, or $172,859. Our weighted average debt was
approximately $11.0 million. For the three months ended March 31, 2001, interest
expense totaled $32,296 on weighted average debt of approximately $1.9 million.
Capitalized interest for the prior year period was $24,402. Also included in
interest expense were deferred loan costs of $25,344 and $25,811 for the three
months ended March 31, 2002 and 2001, respectively. Interest income totaled
$3,878 for the three months ended March 31, 2002 and $22,901 for the 2001
period.

       An income tax benefit was recorded for the first quarter of 2002 of
$117,387 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. For the three months ended March 31, 2001, we provided a charge of
approximately $1.0 million for income taxes at an effective rate of 14% based on
the forecast of annual 2001 net income using assumptions known at that time.

      For the first quarter of 2002, we realized a net loss of $(206,908), or
basic and diluted loss per share of $(0.02), respectively. For the first quarter
of 2001, we reported net income of $6,450,516 or $0.70 basic earnings per share.
Pro forma net income, excluding the non-cash compensation cost related to FIN
44, was a loss of $(207,102), or $(0.02) per share for the first quarter of 2002
and income of $5,798,426, or $0.63 per share for the first quarter of 2001.
Weighted average shares outstanding increased from approximately 9,223,976
shares for the three months ended March 31, 2001 to 9,324,875 shares in the
comparable 2002 period. The increase was due primarily to the exercise of stock
options and the issuance of common stock related to a 2000 restricted stock
grant.


      LIQUIDITY AND CAPITAL RESOURCES

      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 2002 capital expenditures,
commitments and working capital requirements through cash flows from operations,
and to the extent necessary other financing activities. The projected 2002 cash
flows from operations are estimated to be sufficient to fund our budgeted
exploration and development program. We believe we will be able to generate
resources and liquidity sufficient to fund our capital expenditures and meet
such financial obligations as they come due. In the event such capital resources
are not available to us, our drilling and other activities may be curtailed.

Liquidity

      We had cash and cash equivalents at March 31, 2002 of $307,264 consisting
primarily of short-term money market investments, as compared to $793,287 at
December 31, 2001. Our working capital surplus was $1.8 million at March 31,
2002, as compared to $682,065 at December 31, 2001, and our ratio of current
assets to current liabilities was 1.4:1 at March 31, 2002 compared to 1.1:1 at
December 31, 2001. At March 31, 2002, $11.5 million in borrowings were
outstanding under our Credit Facility compared to $10.0 million in borrowings at
December 31, 2001. Our working capital surplus and increased current ratio at
March 31, 2002 resulted primarily from a reduction in our accrued liabilities
partially offset by increased trade payables and lower accounts receivable.


Cash Flows

      Cash flows provided by operating activities were $896,402 and $8.2 million
for the three months ended March 31, 2002 and 2001, respectively. The decrease
in cash flows provided by operations for the three months ended March 31, 2002
is primarily due to significantly lower average prices received for our
production in the first quarter of 2002 compared to the same period in 2001.
Working capital usage for the three months ended March 31, 2002 was $1.6 million
as compared to $489,066 for the same period in 2001. Operating cash flows,
before changes in working capital, were $2.5 million and $8.7 million for the
three months ended March 31, 2002 and 2001, respectively. Operating cash flow
should not be considered in isolation or as a substitute for net income,
operating income, cash flows from operating activities or any other measure of
financial performance presented in accordance with generally accepted accounting
principles or as a measure of profitability or liquidity.



                                       14
<PAGE>


      Cash used in investing activities totaled $2.9 million for the three
months ended March 31, 2002 compared to $2.6 million used in the same period of
2001. All costs for these periods were associated with capital expenditures. We
expended $1.3 million in our drilling operations resulting in the drilling of 2
gross (0.4785 net) wells during the first quarter of 2002 as compared to 2 gross
(0.8155 net) wells during the same period in 2001. In addition to capital
expenditures for drilling operations, approximately $985,800 was expended on
land and seismic activities. The remaining costs capitalized to oil and natural
gas properties were internal geological and geophysical costs and interest of
approximately $542,600. Total capital expenditures for 2002 are expected to be
approximately $18.6 million.

      Cash provided by financing activities totaled $1.5 million for the three
months ended March 31, 2002 and included borrowings of $1.5 million and net
proceeds from the exercise of stock options of $2,400. For the three months
ended March 31, 2001, cash used in financing activities totaled $2.8 million,
which included borrowings of $1,000,000 and repayments of $4,000,000 and
proceeds from the exercise of stock options of $174,076.


    CREDIT FACILITY

    During the first quarter of 2002, we borrowed $1.5 million under our credit
facility (the "Credit Facility") and as of March 31, 2002, $11.5 million was
outstanding. Borrowings under the Credit Facility bear interest at a rate equal
to prime plus 0.50% or LIBOR plus 2.75%. The Credit Facility matures October 6,
2003 and is secured by substantially all of our oil and natural gas properties.

    In January 2002, the borrowing base was increased to $18 million. The
borrowing base will be re-determined again during the second quarter of 2002.
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. 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 .40 to 1.0. At March 31,
2002, we were in compliance with the above-mentioned covenants.

TAX MATTERS

        At December 31, 2001, we had cumulative net operating loss carryforwards
("NOLs") for federal income tax purposes of approximately $18.2 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. In the
fourth quarter of 2001 we reversed the previous valuation allowance that offset
our deferred tax assets. To the extent that we have financial statement income
in the future, we will require a tax provision in our consolidated statement of
operations. Based on anticipated results for the year ending December 31, 2002
using current assumptions, we estimate that our effective rate for 2002 will be
approximately 36%.

        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.


                                      15

<PAGE>


      FORWARD LOOKING STATEMENTS

      The statements contained in all parts of this document, including, but not
limited to, those relating to 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 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.


ITEM 3.  QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK

    We are exposed to market risk from changes in interest rates and commodity
prices. We use a credit facility, which has a floating interest rate, to finance
a portion of our operations. We are not subject to fair value risk resulting
from changes in our floating interest rates. The use of floating rate debt
instruments provide a benefit due to downward interest rate movements but does
not limit us to exposure from future increases in interest rates. Based on the
quarter-end March 31, 2002 outstanding borrowings and a floating interest rate
of 4.8%, a 10% change in the interest rate would result in an increase or
decrease of interest expense of approximately $52,500 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. Due to
the instability of prices and to achieve a more predictable cash flow, we may
put in place a hedge on a portion of our production. While the use of these
arrangements may limit the benefit to us of increases in the price of oil and
natural gas, it also limits the downside risk of adverse price movements. 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 provides a minimum realized price for the protected volume yet
preserves any upside in gas prices. Any increase in the price of natural gas
would cause the natural gas floor to expire at no additional cost to the
Company. In order for these instruments to provide any benefit, natural gas
prices must drop below $2.65 per MMbtu before June 30, 2002. At March 31, 2002,
the fair value of the hedge was $53,583.


                                       16
<PAGE>


                           PART II - OTHER INFORMATION

ITEM 1 - LEGAL PROCEEDINGS


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

     In October 2001, the Company was sued by certain mineral owners in its Mew
lease, upon which the Company and its partners drilled and completed the Mew No.
1 well in the Brandon Area, Duval County, Texas. The suit names the Company,
Santos USA and Mark Smith, an independent landman, as Defendants, and is filed
in the 229th Judicial District Court of Duval County, Texas. The suit seeks a
declaratory judgment to set aside certain quitclaim deeds between the Mew
lessors that were intended to result in a partition of the mineral estate
between the various members of the Mew family in the land where the well is
located and other lands. The pleadings allege failure of consideration, fraud,
failure to consummate the partition, bad faith trespass and conversion. As part
of the leasing effort for the prospect, some members of the Mew family had
sought to partition their minerals under the tracts where they owned the surface
in full. The Mew heirs, from whom the Company acquired leases, could lose a
portion of their mineral interest if the quitclaim deeds are set aside. Were
this to happen, it could have the effect of voiding the Company's leases as to
an undivided one-third of the unit acreage for the Mew well and the Mew lease.
Plaintiffs seek unspecified actual and exemplary damages against the Company and
Santos arising out of the alleged fraud committed by the Company and Mark Smith.
They also seek damages from Santos for the value of the oil and natural gas
produced and saved from the Mew well, or alternatively, for the value of the oil
and natural gas produced less the cost of drilling, completing and operating the
well. The Company has a 12.5% working interest in the well. To date, the Mew
well has produced $5.7 million in net revenue and has cost $3.6 million to
drill, complete and operate. Estimated gross proved reserves are 111.6 MBbls and
4.6 Bcf. The Company has filed an answer in the case. Santos has filed a plea of
abatement asking that the case be dismissed for failure to join necessary and
indispensable parties. At this point, it is not possible to determine the
ultimate outcome of this litigation or the exposure, if any, the Company may
have.

     In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in the N. LaCopita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil has filed
a counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. ExxonMobil seeks
unspecified damages for the lost profits on the sale of the hydrocarbons from
this property, and for a determination of whether the Company and the other
working interest owners were in good faith or bad faith in trespassing on this
lease. If a determination of bad faith is made, the parties will not be able to
recover their costs of developing this property from the revenues therefrom.
While there is always a risk in the outcome of the litigation, the Company
believes there is no question that it acted in good faith and intends to
vigorously defend its position. The Company, along with GMT and the other
partners, are attempting to negotiate a settlement with ExxonMobil that would
allow GMT et al (including the Company) to participate for their respective
shares of a 23% working interest in the Neblett unit, and would allow for the
recovery of well costs. If the case cannot be settled and the title issue is
decided unfavorably, the Company believes that it will ultimately be able to
recover its costs as a good faith trespasser. Due to the uncertainty of the
final outcome, the Company has ceased to record revenue from the properties as
of August 1, 2001, which net to the Company averaged approximately 1.4 Mmcfe/d
of production at the time the well was shut-in. In addition, the Company removed
associated reserves of 1.4 Bcfe from its total proved reserves. The Company
believes this potential loss is not material to its financial condition or
results of operations.

                                       17
<PAGE>


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...  None

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

Exhibit No.
-----------


+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 Incorporated of the Company, as amended
            (Incorporated by reference from exhibit 3.1 to the Company's
            Registration Statement on Form S-4 (Registration No. 333-17269)).

+3.2        -- Bylaws of the Company (Incorporated by Reference from
            exhibit 3.3 to the Company's Quarterly Report on Form 10-Q for
            the quarterly period ended September 30, 1999).

+3.3        -- First Amendment to Bylaws of the Company on September 28,
            1999 (Incorporated by Reference from exhibit 3.2 to the
            Company's Quarterly Report on Form 10-Q for the quarterly
            period ended September 30, 1999).

+4.1        -- Second Amended and Restated Credit Agreement dated October
            6, 2000 by and between Edge Petroleum Corporation, Edge
            Petroleum Exploration Company and Edge Petroleum Operating
            Company, Inc. (collectively, the "Borrowers") and Union Bank
            Of California, N.A., a national banking association, as Agent
            for itself and as lender. (Incorporated by Reference from
            exhibit 4.5 to the Company's Quarterly Report on Form 10-Q for
            the quarterly period ended September 31, 2000).

+4.2        -- Amendment No. 1 and Waiver dated as of November 11, 2001 by and
            among the lenders party to the Second Amended and Restated Credit
            Agreement dated October 6, 2000 ("Lenders"), Union Bank of
            California, N.A., a national banking association, as agent for
            such Lenders, Edge Petroleum Corporation, Edge Petroleum
            Exploration Company, and Edge Petroleum Operating Company, Inc.
            (collectively, the "Borrowers"), as borrowers under the Second
            Amended and Restated Credit Agreement. (Incorporated by Reference
            from exhibit 4.2 to the Company's Annual Report on Form 10K for
            the annual period ended December 31, 2001).


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<PAGE>


+4.3        -- 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).

+4.4        -- 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).

+4.5        -- 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).

+4.6        -- 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).

+4.7        -- 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).

+4.8        -- 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).

+4.9        -- 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       -- 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)).

+10.4       -- 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)).

+10.5       -- 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).



                                       19
<PAGE>


+10.6       -- Incentive Plan of Edge Petroleum Corporation as Amended and
            Restated Effective as of July 27, 1999, as amended March 1,
            2001. (Incorporated by reference from exhibit 10.6 to the
            Company's Quarterly Report on Form 10-Q for the quarterly
            period ended June 30, 2001).

+10.7       -- 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).

+10.8       -- 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).

+10.9       -- 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).

+10.10      -- 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).

+10.11      -- 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)).

+10.12      -- 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)).


------------------
+ Incorporated by reference as indicated.


     (B)  Reports on Form 8-K......................................   None


                                       20
<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        5/14/02               /S/              John W. Elias
-------------------------        ----------------------------------------------
                                                   John W. Elias
                                              Chief Executive Officer and
                                                 Chairman of the Board

Date        5/14/02               /S/            Michael G. Long
-------------------------        ----------------------------------------------
                                                 Michael G. Long
                                             Senior Vice President and
                                        Chief Financial and Accounting Officer

                                       21