EDGE PETROLEUM CORP - 10-Q Quarterly Report

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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 SEPTEMBER 30, 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.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EDGE PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
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See accompanying notes to consolidated financial statements.

2

EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
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See accompanying notes to consolidated financial statements.

3

EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
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See accompanying notes to consolidated financial statements.

4

EDGE PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
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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.

Our accounting policies are consistent with those discussed in our Form
10-K, except as discussed below. You should refer to our Form 10-K for a further
discussion of those policies.

Revenue adjustment to actual - Year-to-date results for the period ended
September 30, 2002 were favorably impacted by the recognition of revenue
associated with certain underaccruals dating back to 1994. During the second
quarter of 2002, we completed a yearlong project that reconciled amounts
received for production from two of our older producing properties to amounts
accrued in prior periods. After reaching a final determination of ownership
interest, it was determined that over 142,000 thousand cubic feet of gas
equivalent (Mcfe) had been underaccrued over the period from fourth quarter 1994
to present. This resulted in additional revenue of approximately $577,200
reported in the second quarter of 2002. After adjusting for severance taxes,
depletion and income taxes, this had the effect of increasing net income for the
nine months ended September 30, 2002 by approximately $212,300, or $0.02 basic
earnings per share.

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

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS - In August 2001, the Financial
Accounting Standards Board ("FASB") issued Statement of Financial Accounting
Standards ("SFAS") No. 143, Accounting for Asset Retirement Obligations. This
Statement requires companies to record a liability relating to the retirement
and removal of assets used in their business. The liability is discounted to its
present value with a corresponding increase to the related asset value. Over the
life of the asset, the liability will be accreted to its future value and
eventually extinguished when the asset is taken out of service. The Company will
adopt this statement effective January 1, 2003. We are currently evaluating the
effects of this pronouncement.

ACCOUNTING FOR THE IMPAIRMENT OR DISPOSAL OF LONG-LIVED ASSETS - In October
2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets. This Statement requires that long-lived assets that are to be
disposed of by sale be measured at the lower of book value or fair value less
cost to sell. The standard also expanded the scope of discontinued operations to
include all components of an entity with operations of the entity in a disposal
transaction. We adopted the provisions of this statement effective January 1,
2002 and it had no impact on our financial statements.

ACCOUNTING FOR GAINS AND LOSSES FROM EXTINGUISHMENT OF DEBT - In April
2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and
64, Amendment of FASB Statement No. 13, and Technical Corrections. This
Statement rescinds SFAS No. 4, Reporting Gains and Losses from Extinguishment of
Debt, which required all gains and losses from extinguishment of debt to be
aggregated and, if material, classified as an extraordinary item, net of related
income taxes. As a result, the criteria in Accounting Principles Board Opinion
(APB) 30 will now be used to classify those gains and losses. Any gain or loss
on extinguishment of debt that was

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classified as an extraordinary item in prior periods presented that does not
meet the criteria in APB 30 for classification as an extraordinary item shall be
reclassified. The provisions of this Statement are effective for fiscal years
beginning after January 1, 2003.

ACCOUNTING FOR COSTS ASSOCIATED WITH EXIT OR DISPOSAL ACTIVITIES - In July
2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or
Disposal Activities. This Statement requires the recognition of costs associated
with exit or disposal activities when they are incurred rather than at the date
of a commitment to an exit or disposal plan. The provisions of this Statement
are effective for exit or disposal activities initiated after December 31, 2002.

2. LONG-TERM DEBT

During the nine months ended September 30, 2002, we borrowed $8.5 million
and repaid $500,000 under our credit facility (the "Credit Facility"). As of
September 30, 2002, $18.0 million was outstanding with an additional $7.0
million available under our Credit Facility. Borrowings under the Credit
Facility bear interest at a rate equal to prime plus 0.50% or LIBOR plus 2.5%.
In August 2002, the borrowing base was increased to $25 million and the maturity
date extended to October 6, 2004. The Credit Facility is secured by
substantially all of our assets.

We expect the next borrowing base redetermination to occur in the first
quarter of 2003. The borrowing base is not subject to automatic reductions.

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 September
30, 2002, we were in compliance with the above-mentioned covenants.

3. 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 presented as a reconciliation of the numerators and
denominators of basic and diluted earnings per share computations, in accordance
with SFAS No. 128.

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4. 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.

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, a valuation allowance totaling $3.2 million was reversed. We
currently estimate that our effective tax rate for the year ending December 31,
2002 will be approximately 36.9%.

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5. EQUITY

We account for Stock Based Compensation in accordance with SFAS No. 123,
Accounting for Stock Based Compensation. 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 APB 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. At the effective date of SFAS No. 123, we
elected to continue to follow APB No. 25.

Deferred compensation cost reported in accordance with FASB Interpretation
No. (FIN) 44, Accounting for Certain Transactions Involving Stock Compensation,
was a charge of $3,385 for the nine months ended September 30, 2002 compared to
a credit of $850,725 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 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 nine months ended September 30, 2002
and 2001 is presented below:

Supplemental Disclosure of Cash Flow Information

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Interest paid for the nine months ended September 30, 2002 and 2001
excludes amounts capitalized of $505,042 and $24,402, respectively.

7. HEDGING ACTIVITIES

Due to the instability of oil and natural gas prices, we, from time to
time, enter into price risk management transactions (e.g., swaps, collars and
floors) with respect to a portion of our oil and natural gas production in an
effort 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. Such hedging arrangements
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.

The following was the impact on oil and natural gas revenue from hedging
activities for the nine months ended September 30, 2002 and 2001:

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.

Included within oil and natural gas revenue for the nine-month period ended
September 30, 2002 was $(65,550) representing net losses from hedging activity.
In March 2002, we purchased a floor on 18,000 MMbtus per day at $2.65 per MMbtu
for the period April 1, 2002 through June 30, 2002, at a cost of $163,800. On
August 22, 2002, we entered into a fixed float index swap on 5,000 MMbtus per
day at $3.59 per MMbtu for the period September 1, 2002 through December 31,
2002. On August 23, 2002, we entered into a second fixed float index swap on an
additional 5,000 MMbtus per day at $3.685 per MMbtu for the period September 1,
2002 through December 31, 2002. These two swap transactions resulted in a gain
from hedging activity of $98,250 for the three months ended September 30, 2002.
At September 30, 2002, the market value of outstanding hedges was approximately
$(362,128) and is included in accrued liabilities.

Included within oil and natural gas revenue for the nine months ended
September 30, 2001 was $(925,603) 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 was recognized in net income
over the period in which the production hedged originally occurred. As of
September 30, 2001, $536,243 of this loss was recorded to net income with the
balance of $11,517 to be recognized over the remainder of 2001. At September 30,
2001, we did not hold any hedging instruments.

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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. For the reasons expressed 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 seeking to
cancel a portion of our Mew lease, upon which the Company and its partners
drilled and completed the Mew No. 1 well in 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.
Among other things, Plantiffs seek to void the Company's leases as to an
undivided one-third of the unit acreage for the Mew well and the Mew lease.
Plaintiffs also seek unspecified actual and exemplary damages against the
Company and Santos arising out of alleged fraud committed by the Company and
Mark Smith, as well as 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. As
of June 30, 2002, the Mew well has produced $7.3 million in net revenue and has
cost $2.6 million to drill, complete and operate. Estimated remaining gross
proved reserves are 53.6 MBbls and 3.9 Bcf. The Company has filed an answer in
the case and intends to vigorously defend its position that the Mew lease is
valid and subsisting in its entirety. Santos previously filed a plea of
abatement asking that the case be dismissed for failure to join necessary and
indispensable parties. Pursuant to Santos' motion, certain additional defendants
were joined in the case. Pursuant to a mediation held on August 28, 2002, all
parties to this litigation have reached an agreed settlement pursuant to which
the Company will make a one-time payment to the plaintiffs of $264,000 in return
for a full release of all claims (except potential but unasserted drainage
claims) asserted in the lawsuit, and the plaintiffs, as part of such settlement,
will grant to the defendants, including the Company, an oil and gas lease
covering the disputed one-third mineral interest in the Mew well. In addition,
Santos and the other settling defendants release all claims against each other.
Drafts of the settlement documents including the new oil and gas lease, all of
which have been approved by the defendants, have been circulated to plaintiffs
and their counsel for approval. There can be no assurance as to a final
settlement or the terms thereof until all settlement agreements are approved and
executed by all parties.

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 four
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 its 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 litigation, the Company believes
there is no question that it acted in good faith and intends to vigorously
defend its position. If the case cannot be settled and the title issue is

10

decided unfavorably, the Company believes that it will ultimately be able to
recover its drilling and operating 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. The Company and the other working
interest owners in the Neblett Unit have reached an agreement in principal with
ExxonMobil and the landowner, pursuant to which the parties will settle their
disputes in this litigation. Drafts of the settlement documents have been
circulated for review. Pursuant to the terms of the settlement, the Company will
transfer its interest in the Neblett Unit leases to ExxonMobil in return for a
payment from ExxonMobil of $272,800, less any escrow underfundings (the
Company's share of this amount being $86,000). This amount represents
reimbursement of the net, un-recouped costs of drilling, completing, producing
and operating the four Neblett wells. In addition, the landowner will reimburse
the working interest group (including the Company) no later than one year from
the date of the settlement, for the full amount of the lease bonus and certain
excess royalty payments in the aggregate amount of $259,000 (the Company's share
of this amount being $81,000, subject to adjustment for prior ad valorem taxes)
and will indemnify the Company and the other working interest owners from
certain claims of third parties for a portion of the royalty payments. The
Company will hold a lien on the landowner's royalty interest and certain other
collateral until it is paid in full. The Company expects to sign and close the
settlements with ExxonMobil and the landowner during the fourth quarter of 2002,
at which time operations of the property will be turned over to ExxonMobil.
There can be no assurance as to a final settlement or the terms thereof until
all settlement agreements are approved and executed by all parties.

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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

Well activity - The Sonnier No. 1 (Edge W.I. 54.67%) was determined to be
non-productive in October 2002 and was temporarily abandoned pending potential
future use as a saltwater disposal well. In addition, the Thibodeaux No. 1 (Edge
W. I. 45%) has experienced mechanical difficulties. Edge and its partner in the
Thibodeaux well have commenced sidetrack operations in order to achieve a
water-free completion in the existing production zone and to test a shallower
zone. If successful, this operation is expected to return the well to production
early in 2003.

Revenue adjustment to actual - Year-to-date results for the period ended
September 30, 2002 were favorably impacted by the current recognition of revenue
associated with certain underaccruals dating back to 1994. During the second
quarter of 2002, we completed a yearlong project that reconciled amounts
received for production from two of our older producing properties to amounts
accrued in prior periods. After reaching a final determination of ownership
interest, it was determined that over 142,000 thousand cubic feet of gas
equivalent (Mcfe) had been underaccrued over the period from fourth quarter 1994
to present. This resulted in additional revenue of approximately $577,200
reported in the second quarter of 2002. After adjusting for severance taxes,
depletion and income taxes, this had the effect of increasing net income for the
nine months ended September 30, 2002 by approximately $212,300, or $0.02 basic
earnings per share.

Commodity Prices - The average realized price for our production, before
the impact of the second quarter underaccrual adjustment, decreased 40% from
$4.78 per Mcfe for the nine months ended September 30, 2001 to $2.88 per Mcfe
for the comparable period this year. These average prices included the impact of
hedging losses that lowered the realized price by $0.01 per Mcfe and $0.17 per
Mcfe for the nine months ended September 30, 2002 and 2001, respectively.

Debt - As of September 30, 2002, borrowings outstanding under our Credit
Facility totaled $18.0 million compared to borrowings of $10.0 million at
December 31, 2001. During 2001, proceeds from borrowings under the Credit
Facility were used to fund the Gato Creek property acquisition and the cash
payment of $2.5 million to BNP for settlement of litigation. During 2002,
proceeds from borrowings under the Credit Facility were used to fund the
acquisition of additional interest in Gato Creek and other capital expenditures.
In August 2002, our borrowing base was increased from $19.0 million to $25.0
million. In addition, the maturity date was extended to October 6, 2004 with no
automatic monthly borrowing base reductions. We expect the next borrowing base
redetermination to be during the first quarter of 2003.

RESULTS OF OPERATIONS

REVENUE AND PRODUCTION

Oil and natural gas revenue reported for the third quarter of 2002 totaled
$5.2 million, a decrease of 16% compared to the same period in 2001 due to both
lower average realized prices and production declines compared to the prior year
period. Natural gas production comprised 78% of total production on an
equivalent Mcf basis and contributed 79% of total revenue for the third quarter
of 2002. Oil and condensate production was 10% of total production and
contributed 14% of total oil and gas revenue while natural gas liquids (NGLs)
production comprised 12% of total production and contributed 7% of total oil and
gas revenue. In the comparable 2001 period, natural gas production comprised 84%
of total production and contributed 81% of total revenue. Oil and condensate
production

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was 10% of total production and 12% of revenue and NGLs production comprised 6%
of total production and contributed 7% of total revenue for the 2001 period.

Oil and natural gas revenue reported for the nine months ended September
30, 2002 totaled $16.5 million. Excluding the second quarter underaccrual
adjustment, revenue for the nine-month period totaled $15.9 million, a decrease
of 38% over the same period in 2001. While production on a Mcfe basis, excluding
the second quarter 2002 underaccrual adjustment of 142,000 Mcfe, increased 2%
over the prior year period, the impact of lower average realized prices more
than offset the favorable production increase. Natural gas production comprised
80% of total production and contributed 80% of total revenue for the nine months
ended September 30, 2002. Oil and condensate production was 10% of total
production and contributed 14% of total oil and gas revenue while NGL production
comprised 10% of total production and contributed 6% of total oil and gas
revenue. In the comparable 2001 period, natural gas production comprised 88% of
total production and contributed 89% of total revenue. Oil and condensate
production was 9% of total production and 9% of revenue and NGLs production
comprised 3% of total production and contributed 2% of total revenue for the
2001 period.

The following table summarizes volume and price information with respect to
our oil and gas production for the quarter and year-to-date periods ended
September 30, 2002 and 2001. Amounts shown in the table and in the revenue
comparisons discussed below for the nine-month period ended September 30, 2002
excludes the second quarter 2002 underaccrual adjustment of 142,000 Mcfe or
$577,200.

- ----------

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

(2) BPD - barrels per day

THIRD QUARTER 2002 COMPARED TO THE THIRD QUARTER 2001

Natural gas sales revenue decreased 18%, from $5.0 million for the third
quarter of 2001 to $4.1 million for the same period in 2002 due to the impact of
lower average natural gas prices and declines in production. The average
realized price for natural gas production, including the effect of hedging
activity, was $3.01 per Mcf for the third quarter of 2002, a decrease of 9% over
the 2001-third quarter average price of $3.31 per Mcf. This decrease in average
prices decreased revenue by approximately $401,700 (based on 2002 third quarter
production). Production volumes for natural gas for the three months ended
September 30, 2002 decreased 10% to 14,717 MCFGPD from 16,358 MCFGPD for the
third quarter of 2001, due primarily to an overall decline in production at our
Austin and O'Connor Ranch properties and the loss of North La Copita production.
This decrease in natural gas production during the third quarter of 2002
decreased revenue by $499,600 (based on 2001 third quarter average prices).

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Revenue from sales of oil and condensate decreased 5% from $762,692 in the
third quarter of 2001 to $721,733 for the comparable 2002 period due to
decreased production, partially offset by higher average realized prices.
Production volumes for oil and condensate decreased 8% from 338 BPD in the third
quarter of 2001 to 311 BPD for the comparable period in 2002. This decrease in
production decreased quarterly revenue by $63,000 (based on 2001 third quarter
average prices). The average realized price for oil and condensate in the third
quarter of 2002 was $25.26 per barrel compared to $24.49 per barrel for the same
period in 2001. This increase in the average realized price received for our oil
and condensate increased revenue for the third quarter of 2002 by $22,000 (based
on 2002 third quarter production).

Revenue from sales of natural gas liquids (NGLs) decreased 17% from
$435,373 in the third quarter of 2001 to $361,638 for the comparable 2002
period. Higher production was more than offset by the effect of lower prices.
Production volumes for NGLs increased 98% from 190 BPD in the third quarter of
2001 to 376 BPD for the comparable period in 2002 due primarily to production
from our Gato Creek properties. This increase in production favorably impacted
quarterly revenue by $425,300 (based on 2001 third quarter average prices). The
average realized price for NGLs in the third quarter of 2002 was $10.46 per
barrel compared to $24.89 per barrel for the same period in 2001. This decrease
in the average realized price received for our NGLs decreased revenue for the
third quarter of 2002 by $499,000 (based on 2002 third quarter production).

NINE MONTHS ENDED SEPTEMBER 30, 2002 COMPARED TO THE NINE MONTHS ENDED SEPTEMBER
30, 2001

Natural gas sales revenue, excluding the second quarter 2002 underaccrual
adjustment, decreased 44%, from $23.0 million for the nine months ended
September 30, 2001 to $12.7 million for the same period in 2002, due primarily
to lower average natural gas prices and a decrease in production, partially
offset by a greater negative impact of hedging activities in the prior year
period. The average realized price for natural gas production, including the
effect of hedging activity, was $2.90 per Mcf for the 2002 year-to-date period,
a decrease of 40% over the average price for the nine months of 2001 of $4.85
per Mcf. This decrease in average prices decreased revenue by approximately $8.6
million (based on 2002 year-to-date production). Included within natural gas
revenue for the nine months ended September 30, 2002 and 2001 was $(65,550) and
$(925,603), respectively, representing losses from hedging activities.
Production volumes for natural gas for the nine months ended September 30, 2002
decreased 7% from 17,331 MCFGPD for 2001 to 16,106 MCFGPD for the comparable
period in 2002. This decrease in natural gas production during the nine months
ended September 30, 2002 decreased revenue by $1.6 million (based on 2001
year-to-date average prices).

Revenue from sales of oil and condensate, excluding the second quarter 2002
underaccrual adjustment, increased 2% from $2,199,535 for the nine months ended
September 30, 2001 to $2,233,612 for the comparable 2002 period due primarily to
higher average oil production in 2002, partially offset by lower average
realized prices. Production volumes for oil and condensate increased 13% from
308 BPD for the nine months ended September 30, 2001 to 348 BPD for the
comparable period in 2002. This increase in production favorably impacted 2002
year-to-date revenue by $283,200 (based on 2001 year-to-date average prices).
The average realized price for oil and condensate for the nine months ended
September 30, 2002 was $23.51 per barrel, compared to $26.13 per barrel for the
same period in 2001. This decrease in the average realized price received for
our oil and condensate decreased revenue $249,100 (based on 2002 year-to-date
production).

Revenue from sales of natural gas liquids (NGLs), excluding the second
quarter 2002 underaccrual adjustment, increased significantly from $597,531 for
the nine months ended September 30, 2001 to $952,403 for the comparable 2002
period due to higher production, partially offset by lower average realized
prices. Production volumes for NGLs increased 253% from 97 BPD in the nine-month
period of 2001 to 342 BPD for the comparable period in 2002. Due to high natural
gas prices, we elected not to process much of our gas during 2001. This increase
in production favorably impacted year-to-date revenue $1.5 million (based on
2001 year-to-date average prices). The average realized price for NGLs in the
first nine months of 2002 was $10.20 per barrel compared to $22.60 per barrel
for the same period in 2001. This decrease in the average realized price
received for our NGLs decreased revenue by approximately $1.1 million (based on
2002 year-to-date production).

14

COSTS AND OPERATING EXPENSES

Lifting costs for the three-month period ended September 30, 2002 totaled
$610,482, a 28% decrease compared to the same period in 2001. On an equivalent
Mcf basis, lifting costs averaged $0.35 per Mcfe for the three-month period
ended September 30, 2002 compared to $0.48 per Mcfe in the prior year period.
For the nine-month period ended September 30, 2002, lifting costs totaled $1.8
million, a 16% decrease compared to the same period in 2001. Lifting costs were
$0.32 per Mcfe for the nine-month period ended September 30, 2002 ($0.33 per
Mcfe excluding the production associated with the second quarter 2002
underaccrual adjustment) compared to $0.40 per Mcfe in the prior year period.
The decrease in costs was due primarily to lower saltwater disposal costs, lower
natural gas processing costs and lower well control insurance costs recorded in
2002.

Severance and ad valorem taxes for the three months ended September 30,
2002 totaled $437,181, a decrease of 11% from $493,252 in the comparable prior
year period. Severance and ad valorem taxes for the nine months ended September
30, 2002 totaled $1,323,144. Excluding costs associated with the second quarter
2002 underaccrual adjustment, severance and ad valorem taxes totaled $1,258,969
for the nine months ended September 30, 2002, a decrease of 38% from $2.0
million in the comparable prior year period. The decrease in severance and ad
valorem taxes in each of the 2002 periods was due primarily to lower severance
taxes paid on the decreased revenue during the 2002 periods. Severance tax
averaged 6.5% of revenue for the year-to-date 2002 period compared to 7.1% for
the same period in 2001.

Depletion, depreciation and amortization ("DD&A") expense for the
three-month and nine-month periods ended September 30, 2002 totaled $2.7 million
and $8.2 million, respectively. Excluding costs associated with the second
quarter 2002 underaccrual adjustment, DD&A for the nine months ended September
30, 2002 totaled $8.0 million. This compares to DD&A expense for the three-month
and nine-month periods of 2001 that totaled $3.3 million and $7.8 million,
respectively. Full cost DD&A on our oil and natural gas properties totaled $2.5
million for the third quarter of 2002 compared to $3.2 million for the same
period in 2001. On a unit of production basis for the three-month period ended
September 30, 2002 depletion averaged $1.46 per Mcfe compared to $1.77 per Mcfe
in the comparable prior year period. For the nine months ended September 30,
2002 depletion on our oil and natural gas properties totaled $7.7 million ($7.6
million excluding the costs associated with the second quarter 2002 underaccrual
adjustment) compared to $7.3 million for the same period in 2001. On a unit of
production basis depletion for the nine-month period ended September 30, 2002
was $1.36 per Mcfe ($1.37 per Mcfe excluding the production associated with the
second quarter 2002 underaccrual adjustment) compared to $1.35 per Mcfe for the
nine months ended September 30, 2001. For the nine months ended September 30,
2002 as compared to the prior year period, a 1% increase in the overall
depletion rate increased depletion expense by $70,500 ($80,900 excluding the
second quarter 2002 underaccrual adjustment) while higher oil and natural gas
production increased depletion expense by $371,200 ($178,900 excluding the
second quarter 2002 underaccrual adjustment). Other DD&A expense totaled
$155,043 and $482,911 for the three-month and nine-month periods ended September
30, 2002, lower than the comparable prior period totals of $168,691 and
$509,870, respectively.

General and administrative expenses ("G&A") for the third quarter of 2002
decreased 5% to $989,204 from $1,040,788 in the prior year period due primarily
to lower salary and benefit costs and lower general office expense partially
offset by higher investor relation costs and higher franchise taxes compared to
the third quarter of 2001. For the third quarter of 2002 and 2001, overhead
reimbursement fees recorded as a reduction to G&A totaled $114,200 and $35,600,
respectively. Capitalized G&A further reduced total G&A by $370,400 and $411,000
for the three months ended September 30, 2002 and 2001, respectively. For the
nine months ended September 30, 2002, G&A was $3.6 million, a decrease of 2%
compared to the prior year period. For the nine months of 2002 and 2001,
overhead reimbursement fees recorded as a reduction to G&A totaled $177,900 and
$116,300, respectively. Capitalized G&A further reduced total G&A by $1.1
million and $1.2 million for the nine months ended September 30, 2002 and 2001,
respectively. The decrease in G&A for the nine months ended September 30, 2002
was primarily attributable to bad debt expense reserved in 2001, partially
offset by higher salaries and benefits, higher professional services and higher
investor relation costs for 2002 compared to the same period in 2001. In
addition, compensation expense of $100,000 was recorded in the first quarter of
2001 related to the purchase of options from a former employee. G&A on a unit of
production basis for the nine-month periods ended September 30, 2002 and 2001
was $0.63 per Mcfe ($0.65 per Mcfe

15

excluding the production associated with the second quarter 2002 underaccrual
adjustment) and $0.68 per Mcfe ($0.63 per Mcfe excluding the bad debt expense),
respectively.

Deferred compensation expense was $91,952 and $302,262 for the three-month
and nine-month periods ended September 30, 2002, respectively, compared to
deferred compensation expense of $103,011 and $(595,737), respectively, in the
comparable prior year periods. Deferred compensation cost of $3,688 was reported
in accordance with FIN 44 for the three months ended September 30, 2002. No
deferred compensation cost was reported in the comparable 2001 period. Deferred
compensation cost reported in accordance with FIN 44 for the nine months ended
September 30, 2002 totaled $3,385 before taxes compared to a credit of
$(850,725) before taxes, for the same prior year period. Also included in
deferred compensation expense for the three-month and nine-month periods ended
September 30, 2002 was amortization of compensation costs related to restricted
stock grants of $88,264 and $298,877, respectively, compared to amortization of
compensation costs of $103,011 and $254,988 for the comparable 2001 periods.

Other income and (expense) totaled $(80,960) and $(124,502) for the
three-month and nine-month periods ended September 30, 2002, respectively,
compared to other income and (expense) of $(3,376) and $(33,151) in the same
prior year periods. Interest expense incurred during the third quarter of 2002,
totaled $229,778, of which $171,276 was capitalized, on weighted average debt of
$14.3 million. For the nine months ended September 30, 2002, interest expense
incurred totaled $563,545, of which $505,042 was capitalized, on weighted
average debt of $14.2 million for the period. No borrowings under our credit
facility were outstanding during the third quarter of 2001 however we incurred
$16,470 in fees to maintain our available borrowing base. For the nine months
ended September 30, 2001, interest expense totaled $98,766, of which $24,402 was
capitalized. Weighted average debt was $737,000 for the nine months ended
September 30, 2001. Also included in other income and expense was the
amortization of deferred loan costs that totaled $25,344 and $76,031 for the
three-month and nine-month periods ended September 30, 2002, respectively,
compared to amortization of $25,344 and $76,054 for the same periods in 2001.
Partially offsetting these expenses was interest income for the three months and
nine months ended September 30, 2002 of $2,887 and $10,032, respectively,
compared to $38,438 and $117,267 for the same periods in 2001.

For the third quarter of 2002, we reported net income of $156,292 or $0.02
basic earnings per share. This compares to net income of $469,308, or $0.05
basic earnings per share, for the same period in 2001. For the third quarter of
2002, pro forma net income, excluding the non-cash compensation charge related
to FIN 44, was $158,619, or $0.02 per share. The third quarter of 2001 was not
impacted by non-cash deferred compensation expense related to FIN 44.

For the nine months ended September 30, 2002, we reported net income of
$713,369 or $0.08 basic earnings per share. Excluding the second quarter 2002
underaccrual revenue adjustment and associated costs, net income was $501,081,
or $0.05 basic earnings per share. This compares to net income of $10.0 million,
or $1.08 basic earnings per share, for the same period in 2001. Pro forma net
income, excluding the non-cash deferred compensation charge related to FIN 44,
was $715,505, or $0.08 per share for the nine months ended September 30, 2002
($503,217, or $0.05 basic earnings per share excluding the second quarter 2002
underaccrual adjustments) compared to $9.2 million, or $0.99 per share,
excluding the non-cash deferred compensation credit in the comparable 2001
period. Weighted average shares outstanding increased from 9,272,650 shares for
the nine months ended September 30, 2001 to 9,373,831 shares in the comparable
2002 period. The increase was due primarily to the exercise of stock options,
the issuance of common stock related to restricted stock grants and the issuance
of common stock to fund the Company's matching contribution under the 401(k)
plan.

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 the remainder of our 2002 capital
expenditures, commitments and working capital requirements through cash flows
from operations, and to the extent necessary, other financing activities. We
expect that projected 2002 cash flows from operations, combined with modest
additional borrowings under our Credit Facility, will be sufficient to fund our

16

budgeted exploration and development program for 2002. We believe we will be
able to generate resources and liquidity sufficient to fund our capital
expenditures and meet financial obligations as they come due. In the event such
capital resources are not available to us, or we choose to preserve capacity
under our Credit Facility to finance additional acquisitions, our drilling and
other activities may be curtailed.

Liquidity

We had cash and cash equivalents at September 30, 2002 of $915,100
consisting primarily of short-term money market investments, as compared to
$793,287 at December 31, 2001. Our working capital surplus was $3.2 million at
September 30, 2002, as compared to $682,065 at December 31, 2001. Our ratio of
current assets to current liabilities was 1.7:1 at September 30, 2002 compared
to 1.1:1 at December 31, 2001. At September 30, 2002, borrowings outstanding
under our Credit Facility totaled $18.0 million compared to $10.0 million
outstanding at December 31, 2001. Our increases in working capital surplus and
current ratio at September 30, 2002 resulted primarily from lower accrued
liabilities and accounts payable as well as an increase in other assets,
partially offset by lower accounts receivable at September 30, 2002 as compared
with year-end 2001.

Cash Flows

Cash flows provided by operations were $7.0 million and $20.8 million for
the nine months ended September 30, 2002 and 2001, respectively. The decrease in
cash flows provided by operations is primarily due to a decrease in net income
from $10.0 million for the 2001 period to $0.7 million for the same period in
2002. For the nine months ended September 30, 2002, working capital usage
totaled $2.7 million ($2.2 million excluding the second quarter 2002
underaccrual adjustment) compared to a working capital surplus of $2.6 million
for the same period in 2001. Operating cash flows, before changes in working
capital, were $9.7 million ($9.2 million excluding the second quarter 2002
underaccrual adjustment) and $18.2 million for the nine months ended September
30, 2002 and 2001, respectively. Operating cash flow should not be considered in
isolation or as a substitute for net income, operating income, cash flows
provided by 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.

Cash used in investing activities was comprised of capital expenditures
only and totaled approximately $15.0 million for the nine months ended September
30, 2002 compared to $16.4 million used in the same period of 2001. We expended
$8.3 million in our drilling operations resulting in the drilling of 6 gross
(3.1375 net) wells during the 2002 year-to-date period as compared to 18 gross
(7.5393 net) wells during the same period in 2001. Since September 30, 2002, we
have drilled one successful gross well, one gross dry hole and currently one
gross well is drilling. In addition to capital expenditures for drilling
operations for the 2002 period, approximately $1.4 million was incurred to
purchase additional interests in our Gato Creek and Jericho properties, $1.2
million was incurred on currently producing properties and $2.5 million was
expended on land and seismic activities. The remaining cost capitalized to oil
and natural gas properties was internal G&A and interest of approximately $1.6
million.

Cash provided by financing activities totaled $8.1 million for the nine
months ended September 30, 2002 and included borrowings of $8.5 million and
repayments of $0.5 million under our Credit Facility. Other financing activities
included net proceeds from the exercise of stock options of $102,135. For the
nine months ended September 30, 2001, cash used in financing activities totaled
$2.6 million, which included borrowings of $1.0 million and repayments of $4.0
million, as well as proceeds from the exercise of stock options of $390,421.

CREDIT FACILITY

During the nine months ended September 30, 2002, we had net borrowings of
$8.0 million bringing our outstanding debt balance to $18.0 million under our
Credit Facility at September 30, 2002. Borrowings under the Credit Facility bear
interest at a rate equal to prime plus 0.50% or LIBOR plus 2.5%. In August 2002,
our borrowing base was increased from $19.0 million to $25.0 million. In
addition, the maturity date was extended to October 6, 2004 with no automatic
monthly reductions. We expect the next borrowing base redetermination to occur
in the first quarter of 2003. The Credit Facility is secured by substantially
all of our assets.

17

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, of the Company 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 September
30, 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. 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 36.9%.

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.

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 cash flow, capital
resources and liquidity to support working capital and/or capital expenditure
requirements, reinvestment of cash flows, the use of NOLs, tax rates, the
outcome of litigation, the resolution of title matters 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 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, significant capital
requirements of our exploration and development and technology development
programs, the potential impact of government regulations, litigation,
environmental and title matters, our ability to manage our growth and achieve
our business strategy, competition, 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

18

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
outstanding borrowings at September 30, 2002 and a floating interest rate of
4.31%, a 10% change in the interest rate would result in an increase or decrease
of interest expense of approximately $74,000 on an annual basis.

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) with respect to a portion of our oil and natural gas production in an
effort to achieve a more predictable cash flow, as well as to reduce exposure
from price fluctuations. We do not enter into price risk management transactions
for trading or speculative purposes. 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, realized
gains and losses are included in oil and natural gas revenue during the period
the hedged production occurs.

In March 2002, we purchased a floor on 18,000 MMbtus per day at $2.65 per
MMbtu for the period April 1, 2002 through June 30, 2002, at a cost of $163,800.
On August 22, 2002, we entered into a fixed float index swap on 5,000 MMbtus per
day at $3.59 per MMbtu for the period September 1, 2002 through December 31,
2002. On August 23, 2002, we entered into a second fixed float index swap on an
additional 5,000 MMbtus per day at $3.685 per MMbtu for the period September 1,
2002 through December 31, 2002. These two swap transactions resulted in a
realized gain from hedging activity of $98,250 for the three months ended
September 30, 2002. At September 30, 2002, the market value of outstanding
hedges was approximately $(362,128) and is included in accrued liabilities in
the accompanying balance sheet.

ITEM 4. CONTROLS AND PROCEDURES

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

PART 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. For the reasons expressed
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 seeking to
cancel a portion of our Mew lease, upon which the Company and its partners
drilled and completed the Mew No. 1 well in 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

19

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. Among other things, Plaintiffs seek to void the Company's leases
as to an undivided one-third of the unit acreage for the Mew well and the Mew
lease. Plaintiffs also seek unspecified actual and exemplary damages against the
Company and Santos arising out of alleged fraud committed by the Company and
Mark Smith, as well as 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. As of June 30,
2002, the Mew well has produced $7.3 million in net revenue and has cost $2.6
million to drill, complete and operate. Estimated remaining gross proved
reserves are 53.6 MBbls and 3.9 Bcf. The Company has filed an answer in the case
and intends to vigorously defend its position that the Mew lease is valid and
subsisting in its entirety. Santos previously filed a plea of abatement asking
that the case be dismissed for failure to join necessary and indispensable
parties. Pursuant to Santos' motion, certain additional defendants were joined
in the case. Pursuant to a mediation held on August 28, 2002, all parties to
this litigation have reached an agreed settlement pursuant to which the Company
will make a one-time payment to the plaintiffs of $264,000 in return for a full
release of all claims (except potential but unasserted drainage claims) asserted
in the lawsuit, and the plaintiffs, as part of such settlement, will grant to
the defendants, including the Company, an oil and gas lease covering the
disputed one-third mineral interest in the Mew well. In addition, Santos and the
other settling defendants release all claims against each other. Drafts of the
settlement documents including the new oil and gas lease, all of which have been
approved by the defendants, have been circulated to plaintiffs and their counsel
for approval. There can be no assurance as to a final settlement or the terms
thereof until all settlement agreements are approved and executed by all
parties.

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 four
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 its 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 litigation, the Company believes
there is no question that it acted in good faith and intends to vigorously
defend its position. 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 drilling and operating 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. The Company and the other working
interest owners in the Neblett Unit have reached an agreement in principal with
ExxonMobil and the landowner, pursuant to which the parties will settle their
disputes in this litigation. Drafts of the settlement documents have been
circulated for review. Pursuant to the terms of the settlement, the Company will
transfer its interest in the Neblett Unit leases to ExxonMobil in return for a
payment from ExxonMobil of $272,800, less any escrow underfundings (the
Company's share of this amount being $86,000). This amount represents
reimbursement of the net, un-recouped costs of drilling, completing, producing
and operating the four Neblett wells. In addition, the landowner will reimburse
the working interest group (including the Company) no later than one year from
the date of the settlement, for the full amount of the lease bonus and certain
excess royalty payments in the aggregate amount of $259,000 (the Company's share
of this amount being $81,000, subject to adjustment for prior ad valorem taxes)
and will indemnify the Company and the other working interest owners from
certain claims

20

of third parties for a portion of the royalty payments. The Company will hold a
lien on the landowner's royalty interest and certain other collateral until it
is paid in full. The Company expects to sign and close the settlements with
ExxonMobil and the landowner during the fourth quarter of 2002, at which time
operations of the property will be turned over to ExxonMobil. There can be no
assurance as to a final settlement or the terms thereof until all settlement
agreements are approved and executed by all parties.

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

21

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 -- 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 -- 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).

+4.8 -- 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).

+4.9 -- 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).

+4.10 -- 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)).

22

+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).

+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)).

- ----------

* Filed herewith.

+ Incorporated by reference as indicated.

(B) Reports on Form 8-K: The Company filed the following report on Form
8-K:

The Company filed with the Securities and Exchange Commission a Current
Report on Form 8-K dated July 18, 2002, that reported a change in auditors under
Item 4 of Form 8-K.

The Company filed with the Securities and Exchange Commission a Current
Report on Form 8-K dated August 14, 2002, that furnished (not filed)
certifications of its chief executive officer and chief financial officer under
Item 9 of Form 8-K.

23

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 11/11/02 /s/ John W. Elias
- ------------------------ --------------------------------------
John W. Elias
Chief Executive Officer and
Chairman of the Board

Date 11/11/02 /s/ Michael G. Long
- ------------------------ --------------------------------------
Michael G. Long
Senior Vice President and
Chief Financial and Accounting Officer

24

CERTIFICATIONS
Principal Executive Officer

I, John W. Elias, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Edge Petroleum
Corporation.

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons fulfilling the
equivalent function);

a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.

Date: November 11 , 2002 /s/ John W. Elias
----------------------------------
John W. Elias
President, Chief Executive Officer
and Chairman of the Board

25

Principal Financial and Accounting Officer

I, Michael G. Long, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Edge Petroleum
Corporation.

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons fulfilling the
equivalent function);

a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.

Date: November 11, 2002 /s/ Michael G. Long
-----------------------------------------
Michael G. Long
Senior Vice President and Chief Financial
and Accounting Officer

26