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 MARCH 31, 2003

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.)

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

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

1111 Bagby Suite, Suite 2100
Houston, Texas 77002
(Former Address)

Indicate by checkmark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.

Yes [X] No [ ]

Indicate by checkmark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act.)

Yes [ ] No [X]

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

Class Outstanding at May 12, 2003
----- ---------------------------

Common Stock 9,498,016

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)
- --------------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.

3

EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
- --------------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.

4

EDGE PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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

ACCOUNTING CHANGE - In July 2001, the Financial Accounting Standards Board
("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 143,
"Accounting for Asset Retirement Obligations." The statement requires entities
to record a liability for legal obligations associated with the retirement of
tangible long-lived assets in the period in which they are incurred. When the
liability for the fair value of dismantlement and abandonment costs, excluding
salvage values, is initially recorded, the carrying amount of the related
long-lived asset, oil and gas properties, is increased. Accretion of the
liability is recognized each period using the interest method of allocation, and
the capitalized cost is depreciated over the useful life of the related asset.
Upon settlement of the liability, an entity either settles the obligation for
its recorded amount or incurs a gain or loss. The standard is effective for
fiscal years beginning after June 15, 2002, therefore the Company adopted SFAS
No. 143 effective January 1, 2003 using a cumulative effect approach to
recognize transition amounts for asset retirement obligations, asset retirement
costs and accumulated accretion and depreciation. The $357,825 cumulative effect
of the change in prior years (net of income taxes of $192,675) is included in
net income for the three months ended March 31, 2003.

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

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

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

5

In addition, the capitalized costs of oil and natural gas properties
are subject to a "ceiling test," whereby to the extent that such capitalized
costs subject to amortization in the full cost pool (net of depletion,
depreciation and amortization and related deferred taxes) exceed the present
value (using a 10% discount rate) of estimated future net after-tax cash flows
from proved oil and natural gas reserves, such excess costs are charged to
operations. Once incurred, an impairment of oil and natural gas properties in
not reversible at a later date. Impairment of oil and natural gas properties is
assessed on a quarterly basis in conjunction with our quarterly filings with the
Securities and Exchange Commission. No adjustment related to the ceiling test
was required during the three months ended March 31, 2003 or 2002.

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

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

Had compensation expense for stock-based compensation been determined
based on the fair value at the date of grant, our net income, earnings available
to common stockholders and earnings per share would have been reduced and the
stock-based compensation cost would have been increased to the pro forma amounts
indicated below:

The Company is also subject to reporting requirements of Financial
Accounting Standards Board ("FASB") Interpretation No. (FIN) 44, Accounting for
Certain Transactions involving Stock Compensation that requires a non-cash
charge to deferred compensation expense if the market price of our common stock
at the end of a reporting period is greater than the exercise price of certain
stock options. After the first such adjustment is made, each

6

subsequent period is adjusted upward or downward to the extent that the market
price exceeds the exercise price of the options. The charge is related to
non-qualified stock options granted to employees and directors in prior years
and re-priced in May 1999, as well as certain options newly issued in
conjunction with the repricing. No adjustments related to FIN 44 were required
during the first quarter of 2003.

ACCOUNTING PRONOUNCEMENTS

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections". This statement rescinds SFAS No. 4, Reporting Gains and Losses
from Extinguishment of Debt, which required all gains and losses from
extinguishment of debt to be aggregated and, if material, classified as an
extraordinary item, net of income taxes. As a result, the criteria in APB No. 30
will now be used to classify those gains and losses. Any gain or loss on the
extinguishment of debt that was classified as an extraordinary item in prior
periods presented that does not meet the criteria in APB 30 for classification
as an extraordinary item shall be reclassified. The provisions of this Statement
are effective for fiscal years beginning after January 1, 2003. The Company did
not participate in any applicable activities as of and for the period ended
March 31, 2003.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Exit or
Disposal Activities". SFAS No. 146 addresses significant issues regarding the
recognition, measurement and reporting of disposal activities, including
restructuring activities that are currently covered in EITF Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Activity." The
provisions of SFAS No. 146 are effective for exit or disposal activities
initiated after December 31, 2002. The Company did not participate in any
applicable activities as of and for the period ended March 31, 2003.

In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts
(collectively referred to as derivatives) and for hedging activities under SFAS
No. 133, Accounting for Derivative Instruments and Hedging Activities. This
Statement is effective for contracts entered into or modified after June 30,
2003.

During 2002, the FASB issued two interpretations: FIN 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" and FIN 46 "Consolidation of Variable
Interest Entities". There was no current impact of FIN 45 or FIN 46 on the
Company's financial position or results of operations.

The Company does not expect the adoption of any of the above-mentioned
standards to have a material impact on the Company's future financial condition
or results of operations.

2. ASSET RETIREMENT OBLIGATION

In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." The statement requires entities to record a liability
for legal obligations associated with the retirement of tangible long-lived
assets in the period in which they are incurred. When the liability for the fair
value of dismantlement and abandonment costs, excluding salvage values, is
initially recorded, the carrying amount of the related long-lived asset, oil and
gas properties, is increased. Accretion of the liability is recognized each
period using the interest method of allocation, and the capitalized cost is
depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss. The standard is effective for fiscal years beginning
after June 15, 2002, therefore the Company adopted SFAS No. 143 effective
January 1, 2003 using a cumulative effect approach to recognize transition
amounts for asset retirement obligations, asset retirement costs and accumulated
depreciation.

At January 1, 2003, the Company recorded the present value of its
future asset retirement obligation ("ARO") for natural gas and oil property and
related equipment. The cumulative effect of the adoption of SFAS No. 143

7

and the change in accounting principle is a charge to net income during the
first quarter of 2003 of $357,825, net of taxes of $192,675.

The following table summarizes the pro forma net income and earnings
per share for the three months ended March 31, 2002 had SFAS 143 been adopted by
the Company on January 1, 2002.

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

3. LONG TERM DEBT

During the first quarter of 2003, we borrowed $1.7 million under our
credit facility (the "Credit Facility") and as of March 31, 2003, $22.2 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, 2004 and is secured by substantially all of our assets.

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

The Credit Facility provides for certain restrictions, including but
not limited to, limitations on additional borrowings and issues of capital
stock, sales of oil and natural gas properties or other collateral, and engaging
in merger or consolidation transactions. The Credit Facility also prohibits
dividends and certain distributions of cash or properties and certain liens. The
Credit Facility also contains certain financial covenants. The EBITDA to
Interest Expense Ratio requires that (a) our consolidated EBITDA, as defined in
the agreement, for the four fiscal quarters then ended to (b) our consolidated
interest expense for the four fiscal quarters then ended, to not be less than
3.5 to 1.0. EBITDA was part of a negotiated covenant with our lender and is
presented here as disclosure of our compliance with that covenant. The Working
Capital ratio requires that the amount of our consolidated current assets less
our consolidated liabilities, as defined in the agreement, be at least $1.0
million. The Allowable Expenses ratio requires that (a) the aggregate amount of
our year-to-date consolidated general and administrative expenses for the period
from January 1 of such year through the fiscal quarter then ended to (b) our
year-to-date consolidated oil and gas revenue, net of hedging activity, for the
period from January 1 of such year through the fiscal quarter then ended, to be
less than .40 to 1.0. At March 31, 2003, we were in compliance with the
above-mentioned covenants.

8

4. 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, 2003:

5. 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.

We currently estimate that our effective tax rate for the year ending
December 31, 2003 will be approximately 35.7%. For the three months ended March
31, 2003, a provision for income taxes of $521,722 was reported. As a result of
incurring a loss in the first quarter of 2002, an income tax benefit of $117,387
was recorded.

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

A summary of non-cash investing and financing activities for the three
months ended March 31, 2003 and 2002 is presented below:

9

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,
2003 and 2002 is presented below:

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Interest paid for the three months ended March 31, 2003 and 2002
excludes amounts capitalized of $75,923 and $172,859, respectively.

7. HEDGING ACTIVITIES

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

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, 2003:

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

In October 2002, we entered into a natural gas collar that covered
10,000 MMbtus per day for the period January 1, 2003 to December 31, 2003 at a
floor of $4.00 per MMbtu and a ceiling of $4.25 per MMbtu. At March 31, 2003,
the market value of outstanding hedges was approximately $(2.3) million and is
included in current liabilities.

10

In March 2002, we purchased a floor on 18,000 MMbtus per day at $2.65
per MMbtu for the period April 1, 2002 through June 30, 2002, at a cost of
$163,800. The floor structure provided a minimum realized price for the
protected volume yet preserved any upside in gas prices. Any increase in the
price of natural gas caused the natural gas floor to expire at no additional
cost to the Company. At March 31, 2002, the fair value of the hedge was $53,583.

Subsequent to March 31, 2003, the Company entered into a natural gas
collar covering 2,000 MMbtu per day for the period June 1, 2003 to September 30,
2003 with a floor of $5.00 per MMbtu and a ceiling of $6.50 per MMbtu.

8. COMMITMENTS AND CONTINGENCIES

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

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

11

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

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

GENERAL OVERVIEW

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

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

REVENUE RECOGNITION

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

OIL AND NATURAL GAS PROPERTIES

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

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

12

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

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

In addition, the capitalized costs of oil and natural gas properties
are subject to a "ceiling test," whereby to the extent that such capitalized
costs subject to amortization in the full cost pool (net of depletion,
depreciation and amortization and related deferred taxes) exceed the present
value (using a 10% discount rate) of estimated future net after-tax cash flows
from proved oil and natural gas reserves, such excess costs are charged to
operations. Once incurred, an impairment of oil and natural gas properties in
not reversible at a later date. Impairment of oil and natural gas properties is
assessed on a quarterly basis in conjunction with our quarterly filings with the
Securities and Exchange Commission. No adjustment related to the ceiling test
was required during the three months ended March 31, 2003 or 2002.

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

OIL AND NATURAL GAS RESERVES

There are uncertainties inherent in estimating oil and natural gas
reserve quantities, projecting future production rates and projecting the timing
of future development expenditures. In addition, reserve estimates of new
discoveries are more imprecise than those of properties with a production
history. Accordingly, the reserve estimates of new discoveries are subject to
change as additional information becomes available. Proved reserves are the
estimated quantities of crude oil, condensate and natural gas that geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions at the end of the respective years. Proved developed reserves are
those reserves expected to be recovered through existing equipment and operating
methods.

DERIVATIVES AND HEDGING ACTIVITIES

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

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

Upon entering into a derivative contract, we designate the derivative
instruments as a hedge of the variability of cash flow to be received (cash flow
hedge). In accordance with SFAS No. 133, we formally document all relationships
between hedging instruments and hedged items, as well as our risk management
objectives and strategy for undertaking various hedge transactions. We also
formally assess, both at the hedge's inception and on an ongoing basis, whether
the derivatives that are used in hedging transactions are expected to be highly
effective in offsetting changes in cash flows of hedged transactions. All of our
derivative instruments at March 31, 2003 were designated and effective as cash
flow hedges. When it is determined that a derivative is not highly effective as
a hedge or that it has ceased to be a highly effective hedge, hedge accounting
would be discontinued prospectively.

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

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

STOCK-BASED COMPENSATION

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

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

14

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

OVERVIEW

The following matters had a significant impact on our results of
operations and financial position for the three months ended March 31, 2003:

Commodity Prices - The average realized price for our production,
before the effects of hedging activity, increased 142% from $2.42 per thousand
cubic feet of gas equivalent (Mcfe) in the first three months of 2002 to $5.85
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, 2003 resulted in a net realized loss of $(2.2)
million, or $(1.43) per Mcfe.

Cumulative Effect of Accounting Change - We adopted SFAS No. 143,
"Accounting for Asset Retirement Obligations," effective January 1, 2003. We
used a cumulative effect approach to recognize transition amounts for asset
retirement obligations, asset retirement costs and accumulated depreciation. The
$357,825 cumulative effect of the change in accounting (net of income taxes of
$192,675) is included in net income for the three months ended March 31, 2003.

RESULTS OF OPERATIONS

REVENUE AND PRODUCTION

Oil and natural gas production decreased 24% from an average of 22.5
MMcfe per day in the first quarter of 2002 to 17.2 MMcfe per day in the same
current year period; however, the impact of higher average realized prices
offset the production decrease. Oil and natural gas revenue for the first
quarter of 2003 increased 39% over the same period in 2002. Natural gas
production comprised 74% of total production on an equivalent Mcf basis and
contributed 77% of total revenue for the first quarter of 2003. Oil and
condensate production was 11% of total production and contributed 14% of total
oil and gas revenue while natural gas liquids (NGLs) production comprised 15% of
total production and contributed 9% of total oil and gas revenue. In the
comparable 2002 period, natural gas production comprised 84% of total production
and contributed 86% of total revenue. Oil and condensate production was 9% of
total production and 10% of revenue and NGLs production comprised 7% of total
production and 4% of total revenue.

The following table summarizes volume and price information with
respect to our oil and gas production for the quarters ended March 31, 2003 and
2002:

15

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

(2) Excluding losses from hedging activities

(3) BPD - barrels per day

FIRST QUARTER 2003 COMPARED TO THE FIRST QUARTER 2002

Natural gas revenue increased 25% from $4.2 million for the first
quarter of 2002 to approximately $5.3 million for the same period in 2003.
Significantly higher average prices received for our natural gas production more
than offset the decline in production. The average natural gas sales price for
production in the first quarter of 2003 was $4.63 compared to $2.47 per Mcf for
2002. This increase in average price received resulted in increased revenue of
approximately $2.5 million (based on current year production). Included within
natural gas revenue for the three months ended March 31, 2003 was $(2.2) million
representing realized losses from hedging activity that decreased the effective
natural gas sales price by $(1.94) per Mcf. No hedges were in place during the
first quarter of 2002. For the three months ended March 31, 2003, natural gas
production decreased 33% from 18.9 MMcf/d in 2002 to 12.6 MMcf/d in 2003 due
primarily to declines in production from existing properties and the delay in
the resumption of production from the Thibodeaux well, partially offset by
production from new wells drilled including the O'Connor Ranch East properties
and the Gato Creek properties. The decrease in production for the three months
ended March 31, 2003 compared to the same period in 2002 resulted in a decrease
in revenue of approximately $1.4 million (based on 2002 first quarter average
prices).

Revenue from sales of oil and condensate increased 94% from $504,534 in
the first quarter of 2002 to $977,192 for the comparable 2003 period, due
primarily to higher average realized prices. The average realized price for oil
and condensate in the first quarter of 2003 was $33.73 per barrel, a 94%
increase over the first quarter 2002 average price of $17.41 per barrel. This
increase in the average realized price received for our oil and condensate
increased revenue $472,600 (based on current quarter production). Production
volumes for oil and condensate were comparable to the prior year period at 322
BPD.

Revenue from sales of NGLs increased significantly from $187,720 in the
first quarter of 2002 to $584,358 for the comparable 2003 period due to both
higher average realized prices and higher production. The average realized price
for NGLs in the first quarter of 2003 was $14.91 per barrel compared to $7.50
per barrel for the same period in 2002. This 99% increase in the average
realized price for our NGLs increased revenue by $290,500 (based on current
quarter production). Production volumes for NGLs increased from 278 BPD in the
first quarter of 2002 to 436 BPD for the comparable period in 2003. This
increase in production favorably impacted quarterly revenue $106,100 (based on
2002 first quarter average prices).

COSTS AND OPERATING EXPENSES

Lifting costs for the three-month period ended March 31, 2003 totaled
$594,804, comparable to the same period in 2002. Lifting costs averaged $0.38
per Mcfe for the three-month period ended March 31, 2003 compared to $0.29 per
Mcfe in the prior year period due to the lower production reported for the 2003
period compared to 2002.

Severance and ad valorem taxes for the three months ended March 31,
2003 increased 19% from $435,722 in the prior year period to $519,155 in 2003,
due primarily to higher severance taxes paid on the significantly higher revenue
during the first quarter of 2003. Severance and ad valorem taxes were $0.34 per
Mcfe and $0.21 per Mcfe for the three-month periods ended March 31, 2003 and
2002, respectively. The increase in expense per Mcfe is due primarily to the
higher revenue received while production was lower over the comparable periods.
Severance tax averaged 5.0% of revenue for the first quarter of 2003 compared to
7.3% for the same period in 2002 due to tax abatements received on several of
our properties in the fourth quarter of 2002 and first quarter of 2003.

Depletion, depreciation and amortization expense ("DD&A") expense for
the first quarter of 2003 totaled $2.7 million compared to $2.8 million in the
first quarter of 2002. Full cost DD&A on our oil and natural gas properties
totaled $2.5 million for the first quarter of 2003 compared to $2.7 million for
the same period in 2002.

16

Depletion expense on a unit of production basis for the three-month periods
ended March 31, 2003 and 2002 was $1.62 per Mcfe and $1.31 per Mcfe,
respectively. For the first quarter of 2003 as compared to the prior year
period, a 24% increase in the overall depletion rate increased depletion expense
by $469,500 while lower oil and natural gas production decreased depletion
expense by $631,000. The increase in the depletion rate was primarily due to a
higher amortizable base at March 31, 2003 compared to March 31, 2002. Other DD&A
expense of $229,784 for the three-month period ended March 31, 2003 was higher
than the comparable prior period total of $167,635 due to the accelerated
amortization of leasehold costs associated with our prior office building lease.

General and administrative expenses ("G&A") for the first quarter of
2003, excluding deferred compensation expense related to restricted stock and
FIN 44 requirements, increased 1% to $1,256,262, as compared to $1,241,418 for
the three months ended March 31, 2002. The increase in G&A was primarily
attributable to higher professional services for the first quarter of 2003
compared to the same period in 2002. For the first quarter of 2003 and 2002,
overhead reimbursement fees recorded as a reduction to G&A totaled $28,700 and
$32,800, respectively. Capitalized G&A further reduced total G&A by $302,800 and
$370,400 for the three months ended March 31, 2003 and 2002, respectively. G&A
on a unit of production basis for the three-month periods ended March 31, 2003
and 2002 was $0.81 per Mcfe and $0.61 per Mcfe, respectively. The increase in
cost per Mcfe is due almost entirely to the lower production for the first
quarter of 2003 compared to the same period in 2002.

Deferred compensation includes amortization related to restricted stock
awards granted during 2001, 2002 and 2003. For the three months ended March 31,
2003 and 2002, such amortization totaled $86,664 and $105,181, respectively.

Also included in deferred compensation are charges or credits related
to FIN 44, "Accounting for Certain Transactions involving Stock Compensation."
FIN 44 requires, among other things, a non-cash charge to compensation expense
if the price of Edge's common stock on the last trading day of a reporting
period is greater than the exercise price of certain options. FIN 44 could also
result in a credit to compensation expense to the extent that the trading price
declines from the trading price as of the end of the prior period, but not below
the exercise price of the options. We adjust deferred compensation expense
upward or downward on a monthly basis based on the trading price at the end of
each such period as necessary to comply with FIN 44. The adjustment is related
only to the non-qualified stock options granted to employees and directors in
prior years and re-priced in May of 1999, as well as certain options newly
issued in conjunction with the repricing. For the three months ended March 31,
2003, no charge or credit was required to comply with FIN 44. For the comparable
2002 period, a credit of $(303) was reported.

For the three months ended March 31, 2003, interest expense totaled
$252,312 on weighted average debt of approximately $21.2 million. Capitalized
interest for the period was $75,923 resulting in net interest expense of
$176,389. 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. Also included in interest expense were deferred
loan costs of $25,344 for the three months ended March 31, 2002. Interest income
totaled $2,123 for the three months ended March 31, 2003 and $3,878 for the 2002
period.

For the three months ended March 31, 2003, we provided a charge of
$521,722 for income taxes at an effective rate of 35.7% based on the forecast of
annual 2003 net income using assumptions known at that time. 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.

We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations,"
effective January 1, 2003. We used a cumulative effect approach to recognize
transition amounts for asset retirement obligations, asset retirement costs and
accumulated depreciation. The $357,825 cumulative effect of the change in
accounting (net of income taxes of $192,675) is included in net income for the
three months ended March 31, 2003.

For the first quarter of 2003, we realized net income of $580,199, or
basic and diluted earnings per share of $0.06. This compares to a net loss for
the first quarter of 2002 of $(206,908), or basic and diluted loss per share of
$(0.02). Weighted average shares outstanding increased from 9,324,875 shares for
the three months ended March

17

31, 2002 to 9,439,858 shares in the comparable 2003 period. The increase was due
primarily to the exercise of stock options and the issuance of common stock
related to restricted stock grants.

LIQUIDITY AND CAPITAL RESOURCES

We had cash and cash equivalents at March 31, 2003 of $588,133
consisting primarily of short-term money market investments, as compared to
$2,568,176 at December 31, 2002. Working capital was $5.6 million as of March
31, 2003, as compared to $3.3 million at December 31, 2002.

Cash flows used in operating activities for the three months ended
March 31, 2003 totaled $(637,815) compared to cash flows provided by operating
activities of $896,402 for the three months ended March 31, 2002. The decrease
in cash flows provided by operating activities in 2003 compared to 2002 was due
primarily to the timing of the settlement of realized hedge losses in relation
to the receipt of cash for the associated revenue stream.

Cash used in investing activities totaled approximately $3.0 million
for the three months ended March 31, 2003 compared to $2.9 million in the same
period of 2002. We expended $2.2 million in our drilling operations resulting in
the drilling of 6 gross (2.45 net) wells during the 2003 first quarter as
compared to 2 gross (0.4785 net) wells during the same period in 2002. Since
March 31, 2003, we have drilled three successful gross wells and one gross dry
hole. Currently one gross well is drilling and one gross well is waiting to be
tested. In addition to capital expenditures for drilling operations for the 2003
period, approximately $131,200 was incurred on currently producing properties
and $215,500 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 $378,800 and other furniture and fixture costs of $163,300. We
received proceeds of approximately $55,100 during the first quarter of 2003 for
the sale of interests in certain oil and gas properties.

Cash flows provided by financing activities totaled $1.7 million for
the three months ended March 31, 2003 compared to $1.5 million for the
comparable 2002 period.

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

CREDIT FACILITY

During the first quarter of 2003, we borrowed $1.7 million under our
credit facility (the "Credit Facility") and as of March 31, 2003, $22.2 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, 2004 and is secured by substantially all of our assets.

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

The Credit Facility provides for certain restrictions, including but
not limited to, limitations on additional borrowings and issues of capital
stock, sales of oil and natural gas properties or other collateral, and engaging
in merger or consolidation transactions. The Credit Facility also prohibits
dividends and certain distributions of cash or properties and certain liens. The
Credit Facility also contains certain financial covenants. The EBITDA to
Interest Expense Ratio requires that (a) our consolidated EBITDA, as defined in
the agreement, for the four fiscal quarters then ended to (b) our consolidated
interest expense for the four fiscal quarters then ended, to not be less than
3.5 to 1.0. EBITDA was part of a negotiated covenant with our lender and is
presented here as disclosure of our compliance with that covenant. The Working
Capital ratio requires that the amount of our consolidated current assets less
our consolidated liabilities, as defined in the agreement, be at least $1.0
million. The Allowable

18

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, 2003, we were in compliance with the above-mentioned
covenants.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections". This statement rescinds SFAS No. 4, Reporting Gains and Losses
from Extinguishment of Debt, which required all gains and losses from
extinguishment of debt to be aggregated and, if material, classified as an
extraordinary item, net of income taxes. As a result, the criteria in APB No. 30
will now be used to classify those gains and losses. Any gain or loss on the
extinguishment of debt that was classified as an extraordinary item in prior
periods presented that does not meet the criteria in APB 30 for classification
as an extraordinary item shall be reclassified. The provisions of this Statement
are effective for fiscal years beginning after January 1, 2003. We did not
participate in any applicable activities as of and for the period ending March
31, 2003.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Exit or
Disposal Activities". SFAS No. 146 addresses significant issues regarding the
recognition, measurement and reporting of disposal activities, including
restructuring activities that are currently covered in EITF Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Activity." The
provisions of SFAS No. 146 are effective for exit or disposal activities
initiated after December 31, 2002. We did not participate in any applicable
activities as of and for the period ending March 31, 2003.

In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts
(collectively referred to as derivatives) and for hedging activities under SFAS
No. 133, Accounting for Derivative Instruments and Hedging Activities. This
Statement is effective for contracts entered into or modified after June 30,
2003.

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

HEDGING ACTIVITIES

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

In October 2002, we entered into a natural gas collar that covered
10,000 MMbtus per day for the period January 1, 2003 to December 31, 2003 at a
floor of $4.00 per MMbtu and a ceiling of $4.25 per MMbtu. At March

19

31, 2003, the market value of outstanding hedges was approximately $(2.3)
million and is included in current liabilities. See Item 3. Qualitative and
Quantitative Disclosures About Market Risk.

In March 2002, we purchased a floor on 18,000 MMbtus per day at $2.65
per MMbtu for the period April 1, 2002 through June 30, 2002, at a cost of
$163,800. The floor structure provided a minimum realized price for the
protected volume yet preserved any upside in gas prices. The natural gas floor
expired at no additional cost to us. At March 31, 2002, the fair value of the
hedge was $53,583.

Subsequent to March 31, 2003, we entered into a natural gas collar
covering 2,000 MMbtu per day for the period June 1, 2003 to September 30, 2003
with a floor of $5.00 per MMbtu and a ceiling of $6.50 per MMbtu.

TAX MATTERS

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

ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk from changes in interest rates and
commodity prices. We use a credit facility, which has a floating interest rate,
to finance a portion of our operations. We are not subject to fair value risk
resulting from changes in our floating interest rates. The use of floating rate
debt instruments provides a benefit due to downward interest rate movements but
does not limit us to exposure from future increases in interest rates. Based on
the quarter-end March 31, 2003 outstanding borrowings and a floating interest
rate of 3.73%, a 10% change in interest rates would result in an increase or
decrease of interest expense of approximately $79,100 on an annual basis.

In the normal course of business we enter into hedging transactions,
including commodity price collars, swaps and floors to mitigate our exposure to
commodity price movements, but not for trading or speculative purposes. During
October 2002, due to the instability of prices and to achieve a more predictable
cash flow, we put in place a natural gas collar for a portion of our 2003
production. While the use of these arrangements limits our ability to benefit
from increases in the price of oil and natural gas, it also reduces our
potential exposure to adverse price movements. The natural gas collar covers
10,000 MMbtu per day for the period January 1, 2003 to December 31, 2003 at a
floor of $4.00 per MMbtu and ceiling of $4.25 per MMbtu. At March 31, 2003, the
fair value of the outstanding hedge was approximately $(2.3) million. A 10%
change in the gas price per MMbtu, as long as the price is either above the
ceiling or below the floor price would cause the fair value total of the hedge
to increase or decrease by approximately $1.2 million.

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.

20

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.

PART II - OTHER INFORMATION

ITEM 1 - LEGAL PROCEEDINGS

From time to time the Company is a party to various legal proceedings
arising in the ordinary course of business. While the outcome of lawsuits cannot
be predicted with certainty, the Company is not currently a party to any
proceeding that it believes, if determined in a manner adverse to the Company,
could have a potential material adverse effect on its financial condition,
results of operations or cash flows, 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 July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in the N. LaCopita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil filed a
counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. ExxonMobil sought
unspecified damages for the lost profits on the sale of the hydrocarbons from
this property, and for a determination of whether the Company and the other
working interest owners were in good faith or bad faith in trespassing on this
lease. If a determination of bad faith were made, the parties would not be able
to recover their costs of developing this property from the revenues therefrom.
While there is always a risk in the outcome of the litigation, the Company
believes there is no question that it acted in good faith and vigorously
defended its position. In February 2003, the Company, GMT and the other working
interest parties entered into a compromise and settlement agreement with Exxon
and Mrs. Neblett. Pursuant to the settlement, the Neblett wells have been
assigned to Exxon along with all operating responsibility, and all working
interest parties, including the Company, have been made whole for all out of
pocket costs incurred in drilling, completing, equipping and operating the
Neblett wells, including lease costs and royalty payments. The Company's share
of such reimbursed costs was $27,198. In addition, Mrs. Neblett will repay the
amount of the lease bonus and all royalty overpayments she received from GMT and
the other working interest parties, including the Company. Such payment is
secured by her future royalty interest payments in the wells, and other security

21

described in the settlement agreement, and is due in full on or before December
1, 2003. The Company's share of such lease bonus and royalty reimbursements is
$74,040. The parties have agreed to a dismissal of all claims in this case, and
an order of dismissal with prejudice has been entered by the court.

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

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...........................................

On May 7, 2003, the Company's board of directors amended the provisions
of the Company's Bylaws requiring that advance notice be delivered to the
Company of any business to be brought by a stockholder before an annual meeting
of stockholders to change the deadline by which the notice must be given to the
Secretary of the Company. As so amended, such advance notice provisions
generally provide that written notice must be given to the Secretary of the
Company by a stockholder (i) in the event of business to be brought by a
stockholder before an annual meeting, not less than 120 days prior to the
anniversary date of the immediately preceding annual meeting of stockholders of
the Company (with certain exceptions if the date of the annual meeting is
different by more than specified amounts from the anniversary date) and (ii) in
the event of nominations of persons for election to the Board of Directors by
any stockholder, (a) with respect to an election to be held at the annual
meeting of stockholders, not less than 120 days prior to the anniversary date of
the immediately preceding annual meeting of stockholders of the Company (with
certain exceptions if the date of the annual meeting is different by more than
specified amounts from the anniversary date) and (b) with respect to an election
to be held at a special meeting of stockholders for the election of directors,
not later than the close of business on the tenth day following the day on which
notice of the date of the special meeting was mailed to stockholders or public
disclosure of the date of the special meeting was made, whichever first occurs.
If the date of the 2004 Annual Meeting of Stockholders is not more than 30 days
before, nor more than 60 days after, the first anniversary of the date of the
2003 Annual Meeting, stockholders who wish to nominate directors or to bring
business before the 2004 Annual Meeting of Stockholders must notify the Company
no later than January 8, 2004. Such notice must set forth specific information
regarding such stockholder and such business or director nominee, as described
in the Company's Bylaws. The Bylaws also provide for certain procedures to be
followed by stockholders in nominating persons for election to the Board of
Directors of the Company.

Compliance with the above procedures does not require the Company to
include the proposal in the Company's proxy solicitation material. Rule 14a-8
under the Securities Exchange Act of 1934, as amended, addresses when a company
must include a stockholder's proposal in its Proxy Statement and identify the
proposal in its form of proxy when the company holds an annual or special
meeting of stockholders. Under Rule 14a-8, proposals that stockholders intend to
have included in the Company's Proxy Statement and form of proxy for the 2004
Annual Meeting of Stockholders must be received by the Company no later than
December 9, 2003. However, if the date of the 2004 Annual Meeting of
Stockholders changes by more than 30 days from the date of the 2003 Annual
Meeting of Stockholders, the deadline by which proposals must be received is a
reasonable time before the Company begins to print and mail its proxy materials,
which deadline will be set forth in a Quarterly Report on Form 10-Q or will
otherwise be communicated to stockholders. Stockholder proposals must also be
otherwise eligible for inclusion.

22

The foregoing information supercedes the information included under "Additional
Information - Stockholder Proposals" in the Company's Proxy Statement dated
April 7, 2003.

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

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

INDEX TO EXHIBITS

23

+4.5 -- Letter Agreement dated October 31, 2000 by and between
Edge Petroleum Corporation, Edge Petroleum Exploration
Company and Edge Petroleum Operating Company, Inc.
(collectively, the "Borrowers") and Union Bank Of
California, N.A., a national banking association, as Agent
for itself and as lender. (Incorporated by Reference from
exhibit 4.6 to the Company's Quarterly Report on Form 10-Q
for the quarterly period ended September 31, 2000).

+4.6 -- Letter Agreement dated March 23, 2001 by and between Edge
Petroleum Corporation, Edge Petroleum Exploration Company
and Edge Petroleum Operating Company, Inc. (collectively,
the "Borrowers") and Union Bank Of California, N.A., a
national banking association, as Agent for itself and as
lender. (Incorporated by Reference from exhibit 4.5 to the
Company's Annual Report on Form 10K for the annual period
ended December 31, 2000).

+4.7 -- Letter Agreement dated September 21, 2001 by and between
Edge Petroleum Corporation, Edge Petroleum Exploration
Company and Edge Petroleum Operating Company, Inc.
(collectively, the "Borrowers") and Union Bank Of
California, N.A., a national banking association, as Agent
for itself and as lender. (Incorporated by Reference from
exhibit 4.6 to the Company's Quarterly Report on Form 10Q
for the quarterly period ended September 30, 2001).

+4.8 -- Letter Agreement dated January 18, 2002 by and between
Edge Petroleum Corporation, Edge Petroleum Exploration
Company and Edge Petroleum Operating Company, Inc.
(collectively, the "Borrowers") and Union Bank Of
California, N.A., a national banking association, as Agent
for itself and as lender. (Incorporated by Reference from
exhibit 4.6 to the Company's Annual Report on Form 10K for
the annual period ended December 31, 2001).

+4.9 -- Letter Agreement dated August 9, 2002 by and between Edge
Petroleum Corporation, Edge Petroleum Exploration Company
and Edge Petroleum Operating Company, Inc. (collectively,
the "Borrowers") and Union Bank Of California, N.A., a
national banking association, as Agent for itself and as
lender. (Incorporated by Reference from exhibit 4.7 to the
Company's Quarterly Report on Form 10Q for the quarterly
period ended June 30, 2002).

+4.10 -- Common Stock Subscription Agreement dated as of April 30,
1999 between the Company and the purchasers named therein
(Incorporated by reference from exhibit 4.5 to the Company's
Quarterly Report on Form 10-Q/A for the quarter ended March
31, 1999).

+4.11 -- Warrant Agreement dated as of May 6, 1999 between the
Company and the Warrant holders named therein (Incorporated
by reference from exhibit 4.5 to the Company's Quarterly
Report on Form 10-Q/A for the quarter ended March 31, 1999).

+4.12 -- Form of Warrant for the purchase of the Common Stock
(Incorporated by reference from the Common Stock
Subscription Agreement from exhibit 4.5 to the Company's
Quarterly Report on Form 10-Q/A for the quarter ended March
31, 1999).

+10.1 -- Joint Venture Agreement between Edge Joint Venture II and
Essex Royalty Limited Partnership II, dated as of May 10,
1994 (Incorporated by reference from exhibit 10.2 to the
Company's Registration Statement on Form S-4 (Registration
No. 333-17269)).

+10.2 -- Joint Venture Agreement between Edge Joint Venture II and
Essex Royalty Limited Partnership, dated as of April 11,
1992 (Incorporated by reference from exhibit 10.3 to the
Company's Registration Statement on Form S-4 (Registration
No. 333-17269)).

+10.3 -- Amendment dated August 21, 2000 to the Joint Venture
Agreement between Edge Joint Venture II and Essex Royalty
Limited Partnership II, dated as of May 10, 1994.
(Incorporated by reference from exhibit 10.2 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 2002).

+10.4 -- Amendment dated August 21, 2000 to the Joint Venture
Agreement between Edge Joint Venture II and Essex Royalty
Limited Partnership, dated as of April 11, 1992.
(Incorporated by reference from exhibit 10.3 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 2002).

24

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

+10.6 -- Form of Indemnification Agreement between the Company and
each of its directors (Incorporated by reference from
exhibit 10.7 to the Company's Registration Statement on Form
S-4 (Registration No. 333-17269)).

+10.7 -- Stock Option Plan of Edge Petroleum Corporation, a Texas
corporation (Incorporated by reference from exhibit 10.13 to
the Company's Registration Statement on Form S-4
(Registration No. 333-17269)).

+10.8 -- Employment Agreement dated as of November 16, 1998, by
and between the Company and John W. Elias. (Incorporated by
reference from 10.12 to the Company's Annual Report on Form
10-K for the year ended December 31, 1998).

+10.9 -- Incentive Plan of Edge Petroleum Corporation as Amended
and Restated Effective as of February 20, 2003.
(Incorporated by reference from exhibit 10.8 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 2002).

+10.10 -- Edge Petroleum Corporation Incentive Plan "Standard
Non-Qualified Stock Option Agreement" by and between Edge
Petroleum Corporation and the Officers named therein.
(Incorporated by reference from exhibit 10.2 to the
Company's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1999).

+10.11 -- Edge Petroleum Corporation Incentive Plan "Director
Non-Qualified Stock Option Agreement" by and between Edge
Petroleum Corporation and the Directors named therein.
(Incorporated by reference from exhibit 10.3 to the
Company's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1999).

+10.12 -- Severance Agreements by and between Edge Petroleum
Corporation and the Officers of the Company named therein
(Incorporated by reference from Exhibit 10.4 to the
Company's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1999).

+10.13 -- Form of Employee Restricted Stock Award Agreement under
the Incentive Plan of Edge Petroleum Corporation
(Incorporated by Reference from exhibit 10.15 to the
Company's Quarterly Report on Form 10-Q/A for the quarterly
period ended March 31, 1999).

+10.14 -- Edge Petroleum Corporation Amended and Restated Elias
Stock Incentive Plan. (Incorporated by reference from
exhibit 4.5 to the Company's Registration Statement on Form
S-8 filed May 30, 2001 (Registration No. 333-61890)).

+10.15 -- Form of Edge Petroleum Corporation John W. Elias
Non-Qualified Stock Option Agreement (Incorporated by
reference from exhibit 4.6 to the Company's Registration
Statement on Form S-8 filed May 30, 2001 (Registration No.
333-61890)).

*99.1 -- Certification by John W. Elias, Chief Executive Officer,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of
Title 18, United States Code).

*99.2 -- Certification by Michael G. Long , Chief Financial and
Accounting Officer, pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of
Section 1350, Chapter 63 of Title 18, United States Code).

* Filed herewith.

+ Incorporated by reference as indicated.

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

25

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 5/14/03 /S/ John W. Elias
- --------------------- ---------------------------------------
John W. Elias
Chief Executive Officer and
Chairman of the Board

Date 5/14/03 /S/ Michael G. Long
- --------------------- ---------------------------------------
Michael G. Long
Senior Vice President and
Chief Financial and Accounting Officer

26

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: May 14, 2003 /s/ John W. Elias
----------------------------------------
John W. Elias
President, Chief Executive Officer
and Chairman of the Board

27

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: May 14, 2003 /s/ Michael G. Long
----------------------------------------
Michael G. Long
Senior Vice President and Chief
Financial and Accounting Officer

28

INDEX TO EXHIBITS