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 PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2003

OR

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

For the transition period from to
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Commission file number 0-22149

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

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

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

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

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

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

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

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.

1

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

2

EDGE PETROLEUM CORPORATION

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

3

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (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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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 ("SEC"), 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/A for the year ended December 31,
2002.

RECLASSIFICATIONS - Certain prior period amounts have been reclassified
to conform to the current period's presentation.

ASSET RETIREMENT OBLIGATION - The Company records a liability for legal
obligations associated with the retirement of tangible long-lived assets in the
period in which they are incurred in accordance with Statement of Financial
Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement
Obligations". The Company adopted this policy effective January 1, 2003, using a
cumulative effect approach to recognize transition amounts for asset retirement
obligations, asset retirement costs and accumulated accretion and depletion.
Under this method, when liabilities for dismantlement and abandonment costs,
excluding salvage values, are initially recorded, the carrying amount of the
related oil and gas properties are increased. Accretion of the liability is
recognized each period using the interest method of allocation, and the
capitalized cost is depleted over the useful life of the related asset.

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

ARO liabilities incurred during the quarter ended September 30, 2003
include obligations assumed for approximately 80 wells acquired in South Texas
on September 30, 2003. See Note 9. Liabilities settled during the quarter ended
September 30, 2003 included 11 wells that were plugged.

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

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

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

In accordance with the full cost method of accounting, the Company
capitalizes 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. Oil
and natural gas properties include costs of $7.6 million and $7.9 million at
September 30, 2003 and December 31, 2002, respectively, which were excluded from
capitalized costs being amortized. 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, net of estimated salvage
values.

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

A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and 142 to companies in the extractive industries,
including oil and gas companies. The issue is whether SFAS No. 141 requires
registrants to classify the costs of mineral rights associated with extracting
oil and gas as intangible assets in the balance sheet, apart from other
capitalized oil and gas property costs, and provide specific footnote
disclosures. Historically, the Company has included the costs of mineral rights
associated with extracting oil and gas as a component of oil and gas properties.
If it is ultimately determined that SFAS No. 141 requires oil and gas companies
to classify costs of mineral rights associated with extracting oil and gas as a
separate intangible assets line item on the balance sheet, the Company would be
required to reclassify approximately $21.4 million and $8.8 million at September
30, 2003 and December 31, 2002, respectively, out of oil and gas properties and
into a separate intangible assets line item. These costs include those to
acquire contract based drilling and mineral use rights such as delay rentals,
lease bonuses, commissions and brokerage fees, and other leasehold costs. The
Company's cash flows and results of operations would not be affected since such
intangible assets would continue to be depleted and assessed for impairment in
accordance with full cost accounting rules, as allowed by SFAS No. 142. Further,
the

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Company does not believe the classification of the costs of mineral rights
associated with extracting oil and gas as intangible assets would have any
impact on the Company's compliance with covenants under its debt agreements.

In addition, the capitalized costs of oil and natural gas properties
are subject to a "ceiling test," whereby to the extent that such capitalized
costs subject to amortization in the full cost pool (net of accumulated
depletion, depreciation and amortization and related deferred taxes) exceed the
present value (using a 10% discount rate) of estimated future net after-tax cash
flows from proved oil and natural gas reserves, such excess costs are charged to
expense. Once incurred, an impairment of oil and natural gas properties is not
reversible at a later date. Impairment of oil and natural gas properties is
assessed on a quarterly basis in conjunction with the Company's quarterly
filings with the SEC. No adjustment related to the ceiling test was required
during the nine-month periods ended September 30, 2003 or 2002.

In May 2003, the SEC issued Staff Accounting Bulletin ("SAB") No. 103,
"Update of Codification of Staff Accounting Bulletins." SAB No. 103 revises or
rescinds portions of the interpretive guidance included in the codification of
staff accounting bulletins in order to make this interpretive guidance
consistent with current authoritative accounting and auditing guidance and SEC
rules and regulations. The principal revisions relate to the rescission of
material no longer necessary because of private sector developments in
accounting principles generally accepted in the United States of America, as
well as SEC rulemaking. As specifically related to oil and gas producing
activities, it requires the inclusion of derivative instruments qualifying as
cash flow hedges, in accordance with SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities", in the computation of limitation on
capitalized costs. In the second quarter of 2003, the Company adopted these
provisions and included the effects of hedge gains and losses in the ceiling
test.

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

Had compensation expense for stock-based compensation been determined
based on the fair value at the date of grant, the Company's 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:

7

The Company is 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 the Company's common stock at the end of a
reporting period is greater than the exercise price of certain stock options.
After the first such adjustment is made, each subsequent period is adjusted
upward or downward to the extent that the market price exceeds the exercise
price of the options. The charge is related to non-qualified stock options
granted to employees and directors in prior years and re-priced in May 1999, as
well as certain options newly issued in conjunction with the repricing. No
adjustments related to FIN 44 were required during the nine-month period ended
September 30, 2003. A charge of $3,688 and $3,385 related to FIN 44 was required
during the three and nine months ended September 30, 2002, respectively.

ACCOUNTING PRONOUNCEMENTS

In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts
(collectively referred to as derivatives) and for hedging activities under SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities". SFAS
No. 149 is effective for contracts entered into or modified after June 30, 2003.
This statement did not impact the Company for the nine-month period ended
September 30, 2003.

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

During 2002, the FASB issued two interpretations that could impact the
Company: FIN 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others" and FIN 46
"Consolidation of Variable Interest Entities." There was no current impact of
FIN 45 on the Company's financial position or results of operations. FIN 46
requires an entity to consolidate a variable interest entity if it is the

8

primary beneficiary of the variable interest entity's activities. The primary
beneficiary is the party that absorbs a majority of the expected losses,
receives a majority of the expected residual returns, or both, from the variable
interest entity's activities. Upon its issuance, FIN 46 was applicable
immediately to variable interest entities created, or interests in variable
interest entities obtained, after January 31, 2003. For those variable interest
entities created, or interests in variable interest entities obtained, on or
before February 1, 2003, FIN 46 is required to be applied in the fourth quarter
of 2003. FIN 46 may be applied prospectively with a cumulative-effect adjustment
as of the date it is first applied, or by restating previously issued financial
statements with a cumulative-effect adjustment as of the beginning of the first
year restated. FIN 46 also requires certain disclosures of an entity's
relationship with variable interest entities. The Company is continuing the
process of examining all of its ownership interests to determine the necessary
disclosures and procedures for complying with FIN 46.

The Company shares interests with related parties in a variety of
different partnership and joint venture entities in order to share the rewards
of ownership in certain oil and natural gas royalties. The Company does not
provide supplemental financial support to these entities nor does it have voting
rights. In general, these entities are structured such that the voting and
sharing ratios in these entities are consistent with the allocation of the
entities' distributions of cash from royalty revenues. The Company does not
anticipate that it will be impacted by FIN 46 because there is no investment in
or obligation to share in future capital requirements of these entities. On
September 2, 2003, the Company sold its interests in two of these entities. See
Note 8.

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. LONG TERM DEBT

During the nine months ended September 30, 2003, the Company borrowed
$10.7 million and made repayments of $1.2 million under the Company's credit
facility (the "Credit Facility") and as of September 30, 2003, $30.0 million was
outstanding under the credit facility. Borrowings under the Credit Facility bear
interest at a rate equal to prime plus 0.50% or LIBOR plus 2.75%. The Company
chooses which interest rate will be applied to a specific borrowing. The Credit
Facility matures January 2, 2005 and is secured by substantially all of the
Company's assets.

Effective September 30, 2003, the borrowing base was increased to
$32.0 million. The borrowing base is not subject to automatic reductions at this
time. The Company expects the borrowing base to be redetermined following the
completion of the proposed merger with Miller Exploration Company. See Note 10.

The Credit Facility provides for certain restrictions, including but
not limited to, limitations on additional borrowings and issues of capital
stock, sales of oil and natural gas properties or other collateral, and engaging
in merger or consolidation transactions. The Credit Facility also prohibits
dividends and certain distributions of cash or properties and certain liens. The
Credit Facility also contains certain financial covenants. The EBITDA to
Interest Expense Ratio requires that (a) consolidated EBITDA, as defined in the
agreement, for the four fiscal quarters then ended to (b) 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 the Company's lender and is
presented here to define the Company's requirements to comply with that
covenant. The Working Capital ratio requires that the amount of consolidated
current assets less consolidated liabilities, as defined in the agreement, be at
least $1.0 million. The Allowable Expenses ratio requires that (a) the aggregate
amount of 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)
year-to-date consolidated oil and gas revenue, net of hedging activity, for the
period from January 1 of such year through the fiscal quarter then ended, to be
less than 0.40 to 1.0. At September 30, 2003, the Company was in compliance with
the above-mentioned covenants.

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3. OTHER COMPREHENSIVE INCOME

In accordance with SFAS No. 130, "Reporting Other Comprehensive
Income", the following are the components of other comprehensive income
for the three and nine months ended September 30, 2003 and 2002:

4. EARNINGS PER SHARE

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

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

5. INCOME TAXES

The Company accounts 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.

The Company currently estimates that its effective tax rate for the
year ending December 31, 2003 will be approximately 35.7%. A provision for
income taxes of $2.3 million and $0.4 million was reported for the nine months
ended September 30, 2003 and 2002, respectively.

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

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

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

12

Supplemental Disclosure of Cash Flow Information

Interest paid for the nine months ended September 30, 2003 and 2002
excludes amounts capitalized of $189,697 and $505,042, respectively. The Company
paid no income taxes in 2003 or 2002.

7. HEDGING ACTIVITIES

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

The following table reflects the impact of the Company's hedging
activities on oil and natural gas revenue for the nine months ended September
30, 2003 and 2002:

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

In August 2003, the Company purchased natural gas options that cover
10,000 MMbtus per day for the period January 1, 2004 to December 31, 2004 at a
floor of $4.50 per MMbtu and a ceiling of $7.00 per MMbtu for the first and
fourth quarters of 2004 and $6.00 per MMbtu for the second and third quarters of
2004 for a cost of $686,250. At September 30, 2003 the market value of this
instrument was approximately $1.0 million and is included in current assets.

13

In April 2003, the Company entered into a natural gas collar covering
2,000 MMbtu per day for the period June 1, 2003 to September 30, 2003 with a
floor of $5.00 per MMbtu and a ceiling of $6.50 per MMbtu. The natural gas
collar expired with no additional cost to the Company.

In October 2002, the Company 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
September 30, 2003, the market value of this outstanding hedge was a loss of
approximately $(0.5) million and is included in current assets.

In August 2002, the Company 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 and 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.

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

8. RELATED PARTY TRANSACTIONS

Essex Royalty Joint Ventures -- A company wholly owned by a director of
the Company is the general partner of each of Essex Royalty Limited Partnership
("Essex I L.P.") and Essex Royalty Limited Partnership II ("Essex II L.P."). In
1992 and 1994 a predecessor partnership of the Company entered into Joint
Venture Agreements (the "Essex I Joint Venture" and "Essex II Joint Venture")
with respect to the purchase of certain royalty and non-operating interests in
oil and natural gas properties. The Company previously served as manager of the
Essex I and II Joint Ventures. Effective January 1, 2001, a director of the
Company and a company wholly owned by that director assumed the Company's duties
as manager of the Essex I and II Joint Ventures. Initially, Essex I and II, L.P.
received 100% of all cash distributions pursuant to the sharing ratios until a
certain payout amount had been recouped as defined in the Essex I and II Joint
Venture Agreements, as amended, at which time the sharing ratios shifted to pay
40% and 25%, respectively, to the Company.

Essex I and II Joint Ventures own royalty and overriding royalty
interests in various wells operated by the Company. The Company had not provided
supplemental financial support to these entities nor did it have voting rights.
In general, these entities were structured such that the sharing ratios in these
entities were consistent with the allocation of the entities' distributions of
cash from royalty revenues. On September 2, 2003, the Company sold its interests
in both partnerships to a third party for $275,000. The Company did not retain
any interest or rights with respect to these entities. The proceeds of the sale
were recorded as an adjustment to capitalized property costs.

9. CAPITAL ADDITIONS

On September 30, 2003 the Company closed the acquisition of oil and gas
properties in its core South Texas area for $8.9 million. The Company funded the
acquisition from existing working capital and borrowings under its existing
credit facility.

Based upon the Company's reserve assessment, the acquisition added
approximately 6.0 Bcfe, at closing, of proved reserves. Estimated current daily
production is 1.7 MMcfe. The reserves and production stream are approximately
81% natural gas.

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On August 26, 2003, the Company entered into a new exploration
venture to jointly explore for oil and natural gas in the Southeastern New
Mexico portion of the Permian Basin with two private oil and gas companies, Pure
Energy Group and Chisos Ltd. Edge and its co-explorers agreed to the
establishment of an area of mutual interest (the "AMI") covering all of Eddy and
Lea Counties, as well as a portion of southern Chaves County. Within the AMI,
Pure and Chisos own approximately 47,000 gross (27,000 net) acres of mineral fee
and leasehold, which they have committed to the exploration venture.

The Company will act as operator for the exploration venture and earn,
subject to fulfillment of certain obligations, an assignment of an undivided 50%
working interest and a 37.5% net revenue interest, proportionately reduced, in
all acreage owned in the AMI. In order to earn the interests in the AMI
properties, the Company will pay a total fee of $2.7 million, $1.0 million paid
at closing and the balance to be paid in 17 equal monthly installments, and
commit to the drilling of four Grayburg/San Andres and six Atoka/Morrow wells
within a 12 month time period. In addition to the fee, the Company will carry
Pure and Chisos for certain costs in the obligation wells. All subsequent wells,
new leasehold acreage and any other acquisitions will be done on a pro-rata
basis by all parties.

10. PROPOSED MERGER

On May 29, 2003 the Company announced that it had entered into a
definitive agreement pursuant to which it would acquire 100% of the outstanding
common stock of Miller Exploration Company ("Miller") (the merger). Miller is an
independent oil and gas exploration and production company with exploration
efforts concentrated primarily in the Mississippi Salt Basin of central
Mississippi. The acquired Miller properties are estimated to contain at least
6.8 billion cubic feet equivalent of proved reserves at December 31, 2002, of
which approximately 74% was natural gas and 94% was classified as proved
developed and the remaining amounts were classified as proved undeveloped.
Miller operates the majority of its properties. The gross acreage position is
approximately 289,088 acres in the United States at December 31, 2002.

The transaction is subject to stockholder approval from both companies
and other customary conditions. Upon closing, the merger will be accounted for
as a purchase of Miller by the Company in a stock-for-stock transaction.

Under the terms of the merger agreement, based on the number of shares
of Miller common stock outstanding as of October 31, 2003 and given a merger
ratio of between 1.22 and 1.30 shares of the Company's common stock for each
share of Miller common stock, the Company would issue between approximately
2,597,475 and 2,767,801 shares of the Company's common stock in the merger. The
merger ratio will be finally determined based on the average closing price of
the Company's common stock over a 20-day period ending five days prior to the
date of the Miller stockholder meeting, which is scheduled for December 4, 2003.
Based upon the average closing price of the Company's common stock over the 20
trading day period ending October 29, 2003 and the number of shares of Miller
common stock outstanding on October 31, 2003 of 2,129,078, Miller stockholders
would have received approximately 2,597,475 shares of the Company's common stock
in the merger and the total shares of the Company common stock outstanding after
this transaction would total approximately 12,148,666. The aggregate value of
the transaction will include transaction costs of approximately $0.7 million.
The merger is expected to qualify as a tax free reorganization under Section
368(a) of the Internal Revenue Code. Accordingly, the merger is expected to be
tax free to the Company's stockholders and for the stock portion of the
consideration received by Miller stockholders.

The special meeting of stockholders for both companies is scheduled for
December 4, 2003 to vote upon the transaction. Assuming a merger ratio of 1.22
(which would be the merger ratio if the Miller stockholder's meeting were to be
held on November 14, 2003), after the merger is consummated, Miller common
stockholders would own approximately 21% of the combined company and Edge
stockholders would own approximately 79% of the combined company. If the
transaction is not completed, merger costs incurred and capitalized in oil and
natural gas properties, through September 30, 2003 totaling approximately
$500,000 will be expensed. Additionally, in the event of certain terminations of
the Merger Agreement, a fee of $345,000 and reimbursement of costs, not to
exceed $500,000, would be required to be paid to Miller and expensed.

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11. SUBSEQUENT EVENTS

Subsequent to September 30, 2003, the Company announced its intent to
acquire certain South Texas oil and gas properties with an estimated 0.5 to 1.0
Bcfe of proved reserves, and allowing the Company to take over operations in
wells where it is currently a minority owner and accelerate the drilling of a
proved undeveloped opportunity. This acquisition is expected to close in the
fourth quarter of 2003.

12. 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.

16

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

The following is management's discussion and analysis of 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/A
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, depletion, 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 capitalize a
portion of interest expense on borrowed funds. Employee related costs that are
directly attributable to exploration and development activities are also
capitalized. These costs are considered to be direct costs based on the nature
of their function as it relates to the exploration and development function.

17

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. Oil
and natural gas properties include costs of $7.6 million and $7.9 million at
September 30, 2003 and December 31, 2002, respectively, which were excluded from
capitalized costs being amortized. 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, net of estimated salvage
values.

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

A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and 142 to companies in the extractive industries,
including oil and gas companies. The issue is whether SFAS No. 141 requires
registrants to classify the costs of mineral rights associated with extracting
oil and gas as intangible assets in the balance sheet, apart from other
capitalized oil and gas property costs, and provide specific footnote
disclosures. Historically, we have included the costs of mineral rights
associated with extracting oil and gas as a component of oil and gas properties.
If it is ultimately determined that SFAS No. 141 requires oil and gas companies
to classify costs of mineral rights associated with extracting oil and gas as a
separate intangible assets line item on the balance sheet, we would be required
to reclassify approximately $21.4 million and $8.8 million at September 30, 2003
and December 31, 2002, respectively, out of oil and gas properties and into a
separate intangible assets line item. These costs include those to acquire
contract based drilling and mineral use rights such as delay rentals, lease
bonuses, commissions and brokerage fees, and other leasehold costs. Our cash
flows and results of operations would not be affected since such intangible
assets would continue to be depleted and assessed for impairment in accordance
with full cost accounting rules, as allowed by SFAS No. 142. Further, we do not
believe the classification of the costs of mineral rights associated with
extracting oil and gas as intangible assets would have any impact on our
compliance with covenants under our debt agreements.

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

In addition, the capitalized costs of oil and natural gas properties
are subject to a "ceiling test," whereby to the extent that such capitalized
costs subject to amortization in the full cost pool (net of accumulated
depletion, depreciation and amortization and related deferred taxes) exceed the
present value (using a 10% discount rate) of estimated future net after-tax cash
flows from proved oil and natural gas reserves, such excess costs are charged to
expense. Once incurred, an impairment of oil and natural gas properties is not
reversible at a later date. Impairment of oil and natural gas properties is
assessed on a quarterly basis in conjunction with our quarterly filings with the
Securities and Exchange Commission ("SEC"). No adjustment related to the ceiling
test was required during the nine-month periods ended September 30, 2003 or
2002.

In May 2003, the SEC issued Staff Accounting Bulletin ("SAB") No. 103,
"Update of Codification of Staff Accounting Bulletins." SAB No. 103 revises or
rescinds portions of the interpretive guidance included in the codification of
staff accounting bulletins in order to make this interpretive guidance
consistent with current authoritative accounting and auditing guidance and SEC
rules and regulations. The principal revisions relate to the rescission of
material no longer necessary because of private sector developments in
accounting principles generally accepted in the United States of America, as
well as SEC rulemaking. As specifically related to oil and gas

18

producing activities, it requires the inclusion of derivative instruments
qualifying as cash flow hedges, in accordance with SFAS No. 133, in the
computation of limitation on capitalized costs. In the second quarter of 2003,
we adopted these provisions and included the effects of hedge gains and losses
in the ceiling test.

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

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

We adopted SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities" effective January 1, 2001. The statement, as amended by SFAS
No. 137 and SFAS No. 138, requires that all derivatives be recognized as either
assets or liabilities and measured at fair value, and changes in the fair value
of derivatives be reported in current earnings, unless the derivative is
designated and effective as a hedge. If the intended use of the derivative is to
hedge the exposure to changes in the fair value of an asset, a liability or firm
commitment, then the changes in the fair value of the derivative instrument will
generally be offset in the income statement by the change in the item's fair
value. However, if the intended use of the derivative is to hedge the exposure
to variability in expected future cash flows then the changes in the fair value
of the derivative instrument will generally be reported in accumulated other
comprehensive income (AOCI). The gains and losses on the derivative instrument
that are reported in AOCI will be reclassified to earnings in the period in
which the hedged transaction occurs.

To date, all derivative contracts entered into have been to hedge the
variability of cash flow to be received (cash flow hedges). 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 September 30, 2003 were designated and effective as cash flow hedges. In the
event it is determined that the use of a particular derivative may not be or has
ceased to be effective in pursuing a hedging strategy, hedge accounting would be
discontinued prospectively.

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

19

derivative will be carried at fair value on the balance sheet with future
changes in its fair value recognized in earnings as the hedged production takes
place.

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

STOCK-BASED COMPENSATION

We account for stock compensation plans under the intrinsic value
method of Accounting Principles Board ("APB") Opinion No. 25, "Accounting for
Stock Issued to Employees." No compensation expense is recognized for stock
options that had an exercise price equal to or greater than the market value of
the 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.

We are also subject to reporting requirements of FASB Interpretation
No. (FIN) 44, "Accounting for Certain Transactions involving Stock Compensation"
that requires a non-cash charge to deferred compensation expense if the market
price of our common stock at the end of a reporting period is greater than the
exercise price of certain stock options. After the first such adjustment is
made, each subsequent period is adjusted upward or downward to the extent that
the market price exceeds the exercise price of the options. The charge is
related to non-qualified stock options granted to employees and directors in
prior years and re-priced in May 1999, as well as certain options newly issued
in conjunction with the repricing. No adjustments related to FIN 44 were
required during the nine-month period ended September 30, 2003.

OVERVIEW

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

Commodity Prices - The average realized price for our production,
before the effects of hedging activity, increased 73% from $2.92 per thousand
cubic feet of gas equivalent (Mcfe) in the first nine months of 2002 to $5.08
per Mcfe for the comparable period this year.

Hedging Activity - For the nine months ended September 30, 2003, we
realized net losses from hedging activities of $(4.2) million, or $(0.76) per
Mcfe. For the nine months ended September 30, 2002, hedging activity resulted in
a net realized loss of $(65,600), or $(0.01) per Mcfe.

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

20

RESULTS OF OPERATIONS

REVENUE AND PRODUCTION

Oil and natural gas revenue for the third quarter of 2003 increased 72%
over the same period in 2002 due to both higher average realized prices and
increased production. The average realized price for our production (including
the impact of hedge activity) was $4.06 per Mcfe for the third quarter of 2003
compared to $2.98 per Mcfe for the same period in 2002. Oil and natural gas
production increased 27% from an average of 18.8 MMcfe per day in the third
quarter of 2002 to 23.8 MMcfe per day in the same current year period. Natural
gas production comprised 79% of total production on an equivalent Mcf basis and
contributed 84% of total revenue for the third quarter of 2003. Oil and
condensate production was 8% of total production and contributed 10% of total
oil and gas revenue while natural gas liquids (NGLs) production comprised 13% of
total production and contributed 6% of total oil and gas revenue. In the
comparable 2002 period, natural gas production comprised 78% of total production
and contributed 79% of total revenue. Oil and condensate production was 10% of
total production and 14% of revenue and NGLs production comprised 12% of total
production and 7% of total revenue.

Oil and natural gas production decreased 3% from an average of 20.8
MMcfe per day in the nine-month period ended September 30, 2002 to 20.1 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 nine months ended September 30, 2003 increased 44% over the same period in
2002. Natural gas production comprised 77% of total production on an equivalent
Mcf basis and contributed 81% of total revenue for the nine months ended
September 30, 2003. Oil and condensate production was 9% of total production and
contributed 12% of total oil and gas revenue while natural gas liquids (NGLs)
production comprised 14% of total production and contributed 7% of total oil and
gas revenue. In the comparable 2002 period, natural gas production comprised 76%
of total production and contributed 78% of total revenue. Oil and condensate
production was 11% of total production and 14% of revenue and NGLs production
comprised 13% of total production and 8% of total revenue.

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

- ----------
(1) MCFGPD - thousand cubic feet of gas per day
(2) Excluding losses from hedging activities
(3) BPD - barrels per day

THIRD QUARTER 2003 COMPARED TO THE THIRD QUARTER 2002

Natural gas revenue increased 84% from $4.1 million for the third
quarter of 2002 to $7.5 million for the same period in 2003 due to a 45%
increase in the average price received for our natural gas production. The
average natural gas sales price for production in the third quarter of 2003 was
$4.36 per Mcf compared to $3.01 per Mcf for 2002. This increase in average price
received resulted in increased revenue of approximately $2.3 million (based on

21

current year production). Included within natural gas revenue for the three
months ended September 30, 2003 was $(0.8) million representing realized losses
from hedging activity that decreased the effective natural gas sales price by
$(0.48) per Mcf. During the third quarter of 2002, realized gains from hedging
activities totaled $98,250 that increased the effective natural gas price by
$0.07 per Mcf. For the three months ended September 30, 2003, natural gas
production increased 27% from 14.7 MMCFGPD in 2002 to 18.7 MMCFGPD in 2003 due
primarily to production from new wells drilled including the O'Connor Ranch East
properties and the Gato Creek properties as well as resumption of production
from the Thibodeaux well partially offset by natural declines in production from
existing properties. The increase in production for the three months ended
September 30, 2003 compared to the same period in 2002 resulted in an increase
in revenue of approximately $1.1 million (based on 2002 third quarter average
prices).

Revenue from sales of oil and condensate increased 25% from $0.7
million in the third quarter of 2002 to $0.9 million for the comparable 2003
period, due to higher average realized prices and higher production volumes. The
average realized price for oil and condensate in the third quarter of 2003 was
$30.18 per barrel, a 19% increase over the third quarter 2002 average price of
$25.26 per barrel. This increase in the average realized price received for our
oil and condensate production increased revenue $147,200 (based on current
quarter production). Production volumes for oil and condensate increased 5%
compared to the prior year period to 325 BPD due to the additional oil and
condensate production from the Thibodeaux well during the third quarter of 2003
compared to the third quarter of 2002. The increase in production of oil and
condensate for the three months ended September 30, 2003 compared to the same
period in 2002 resulted in an increase in revenue of approximately $34,100
(based on 2002 third quarter average prices).

Revenue from sales of NGLs increased from $0.4 million in the third
quarter of 2002 to $0.5 million for the comparable 2003 period due to higher
production. Production volumes for NGLs increased from 376 BPD in the third
quarter of 2002 to 536 BPD for the comparable period in 2003 due primarily to
additional production from the Thibodeaux well partially offset by natural
declines on the Ibarra and La Jolla Parr wells. This increase in production
resulted in an increase in quarterly revenue of $154,000 (based on 2002 third
quarter average prices). The average realized price for NGLs in the third
quarter of 2003 was $10.05 per barrel compared to $10.46 per barrel for the same
period in 2002. This 4% decrease in the average realized price for our NGLs
decreased revenue by $20,200 (based on current quarter production).

NINE MONTHS ENDED SEPTEMBER 30, 2003 COMPARED TO THE NINE MONTHS ENDED SEPTEMBER
30, 2002

Natural gas revenue increased 51% from $12.8 million for the nine-month
period ended September 30, 2002 to $19.3 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 nine months ended September 20, 2003 was $4.59 per Mcf
compared to $2.98 per Mcf for 2002. This increase in average price received
resulted in increased revenue of approximately $6.8 million (based on current
year-to-date production). Included within natural gas revenue for the nine
months ended September 30, 2003 was $(4.2) million representing realized losses
from hedging activity that decreased the effective natural gas sales price by
$(0.99) per Mcf. During the nine months ended September 30, 2002, realized
losses from hedging activities were $(65,600) that decreased the effective
natural gas sales price by $(0.02) per Mcf. For the nine months ended September
30, 2003, natural gas production decreased 2% from 15.7 MMCFGPD in 2002 to 15.4
MMCFGPD in 2003 due primarily to declines in production from existing properties
and the delay in the resumption of production from the Thibodeaux well,
partially offset by production from new wells drilled including the O'Connor
Ranch East properties and the Gato Creek properties. The decrease in production
for the nine months ended September 30, 2003 compared to the same period in 2002
resulted in a decrease in revenue of approximately $0.3 million (based on 2002
year-to-date average prices).

Revenue from sales of oil and condensate increased 17% from $2.3
million in the nine months ended September 30, 2002 to $2.8 million for the
comparable 2003 period, due to higher average realized prices. The average
realized price for oil and condensate in the nine-month period of 2003 was
$32.47 per barrel, a 44% increase over the average price of $22.49 per barrel
for the same 2002 period. This increase in the average realized price received
for our oil and condensate increased revenue by $845,400 (based on current
year-to-date production). Production volumes for oil and condensate decreased
19% from 382 BPD in the nine months ended September 30,

22

2002 to 310 BPD in the 2003 year-to-date period due primarily to natural
declines in production from existing properties. The decrease in production for
the nine months ended September 30, 2003 compared to the same period in 2002
resulted in a decrease in revenue of approximately $438,900 (based on 2002
year-to-date average prices).

Revenue from sales of NGLs increased from $1.4 million in the nine
months of 2002 to $1.7 million for the comparable 2003 period due to higher
production and average realized prices. The average realized price for NGLs in
the nine-month period ended September 30, 2003 was $12.88 per barrel compared to
$10.85 per barrel for the same period in 2002. This 19% increase in the average
realized price for our NGLs increased revenue by $268,200 (based on current
year-to-date production). Production volumes for NGLs increased from 464 BPD in
the first nine months of 2002 to 482 BPD for the comparable period in 2003 due
to additional production from the Thibodeaux well and our Gato Creek properties.
This increase in production resulted in an increase in revenue of $53,900 (based
on 2002 year-to-date average prices).

COSTS AND OPERATING EXPENSES

Lifting costs for the three-month period ended September 30, 2003
totaled $597,600, 2% lower than the same period in 2002. Lifting costs averaged
$0.27 per Mcfe for the three-month period ended September 30, 2003 compared to
$0.35 per Mcfe in the same prior year period due primarily to changing the mix
of production to newer, lower cost wells. For the nine-month period ended
September 30, 2003, lifting costs totaled $1.7 million, a 4% decrease compared
to the same period in 2002. Lifting costs were $0.32 per Mcfe for the nine-month
period ended September 30, 2003 comparable to the prior year period.

Severance and ad valorem taxes for the three months and nine months
ended September 30, 2003 totaled $561,800 and $1,602,800, respectively, compared
to $437,200 and $1,323,100 for the comparable prior year periods. The increase
is due primarily to higher severance taxes paid on the increased revenue
reported for the 2003 periods partially offset by abatements on our Gato Creek
properties in South Texas and the Thibodeaux well in Louisiana. On an equivalent
production basis, severance and ad valorem taxes averaged $0.26 per Mcfe and
$0.29 per Mcfe for the three-month and nine-month periods ended September 30,
2003 compared to $0.25 per Mcfe and $0.23 per Mcfe for the same periods in 2002.
The increase in expense per Mcfe for the nine-month period is due primarily to
the higher revenue received while production was lower over the comparable
period. Severance tax averaged 4.8% of revenue for the nine months ended
September 30, 2003 compared to 6.7% for the same period in 2002 due to the tax
abatements discussed above.

Depletion, depreciation and amortization ("DD&A") expense for the
three-month and nine-month periods ended September 30, 2003 totaled $3.7 million
and $9.3 million, respectively. This compares to $2.7 million and $8.2 million
in the same periods of 2002. Depletion expense on our oil and natural gas
properties totaled $3.6 million for the third quarter of 2003 compared to $2.5
million for the same period in 2002. Depletion expense on a unit of production
basis for the three-month period ended September 30, 2003 was $1.63 per Mcfe
compared to $1.46 per Mcfe in the comparable prior year period. For the nine
months ended September 30, 2003 depletion on our oil and natural gas properties
totaled $8.8 million compared to $7.7 million for the same period in 2002.
Depletion expense on a unit of production basis for the nine-month period ended
September 30, 2003 was $1.60 per Mcfe compared to $1.36 per Mcfe for the nine
months ended September 30, 2002. For the nine months ended September 30, 2003 as
compared to the prior year period, an 18% increase in the overall depletion rate
increased depletion expense by $1.3 million while lower oil and natural gas
production decreased depletion expense by $0.2 million. The increase in the
depletion rate was primarily due to a significantly higher amortizable base at
September 30, 2003 compared to September 30, 2002. Other DD&A expense totaled
$140,100 and $485,800 for the three-month and nine-month periods ended September
30, 2003 compared to the prior period totals of $155,000 and $482,900,
respectively.

Total general and administrative expenses ("G&A") for the third quarter
of 2003 increased 16% from the prior year period to $1.3 million. For the
nine-month period, G&A increased 5% from $3.9 million in the 2002 period to $4.1
million in the same period of 2003. G&A expenses included charges to deferred
compensation related to FIN 44, "Accounting for Certain Transactions involving
Stock Compensation," deferred compensation amortization costs related to
restricted stock awards granted during 2001, 2002 and 2003 and other G&A costs.

23

FIN 44 requires, among other things, a non-cash charge to compensation
expense if the price of Edge's common stock on the last trading day of a
reporting period is greater than the exercise price of certain options. FIN 44
could also result in a credit to compensation expense to the extent that the
trading price declines from the trading price as of the end of the prior period,
but not below the exercise price of the options. We adjust deferred compensation
expense upward or downward on a monthly basis based on the trading price at the
end of each such period as necessary to comply with FIN 44. The adjustment is
related only to the non-qualified stock options granted to employees and
directors in prior years and re-priced in May of 1999, as well as certain
options newly issued in conjunction with the repricing. For the three-month and
nine-month periods ended September 30, 2003, no charge or credit was required to
comply with FIN 44. Deferred compensation expense related to FIN 44 was a net
charge of $3,700 and $3,400 for the three-month and nine-month periods ended
September 30, 2002, respectively.

Deferred compensation amortization costs related to restricted stock
awards totaled $93,600 and $88,300 for the three months ended September 30, 2003
and 2002, respectively. For the nine months ended September 30, 2003 and 2002,
deferred compensation amortization totaled $270,000 and $298,900, respectively.

Other G&A costs for the third quarter of 2003 increased 17% from the
prior year period to $1.2 million. For the third quarter of 2003 and 2002,
overhead reimbursement fees recorded as a reduction to other G&A totaled $30,800
and $114,200, respectively. Capitalized G&A further reduced other G&A by
$571,700 and $370,400 for the three months ended September 30, 2003 and 2002,
respectively. For the nine months ended September 30, 2003, other G&A was $3.8
million, an increase of 7% compared to the prior year period. For the nine
months of 2003 and 2002, overhead reimbursement fees recorded as a reduction to
other G&A totaled $87,000 and $177,900, respectively. Capitalized G&A further
reduced other G&A by $1.2 million and $1.1 million for the nine months ended
September 30, 2003 and 2002, respectively. The increase in other G&A for both
the three months and the nine months ended September 30, 2003 was primarily
attributable to higher audit and legal fees, higher franchise taxes, office
moving costs and the settlement of a lawsuit related to seismic rights in April
2003 for $70,000. These costs were partially offset by lower rent and parking
and lower reserve engineer fees compared to the prior year periods. Other G&A on
a unit of production basis for the nine-month periods ended September 30, 2003
and 2002 was $0.70 per Mcfe and $0.63 per Mcfe, respectively.

For the three months ended September 30, 2003, interest expense totaled
$194,300 on weighted average debt of approximately $21.5 million. Capitalized
interest for the period was $65,700 resulting in net interest expense of
$128,600. For the three months ended September 30, 2002, interest expense
totaled $229,800 on weighted average debt of approximately $17.4 million.
Capitalized interest for the period was $171,300 resulting in net interest
expense of $58,500. Also included in interest expense for the three months ended
September 30, 2002 was $25,300 in deferred loan cost amortization. For the nine
months ended September 30, 2003, interest expense totaled $659,800 on weighted
average debt of approximately $21.4 million compared to interest expense of
$563,500 on weighted average debt of $14.2 million in the comparable 2002
period. Capitalized interest for the nine months ended September 30, 2003 and
2002 totaled $189,700 and $505,000, respectively. Also included in interest
expense were deferred loan costs of $76,000 for the nine months ended September
30, 2002. Net interest expense for the nine months ended September 30, 2003 and
2002 was $470,100 and $134,500, respectively. Interest income totaled $8,300 and
$13,400 for the three-month and nine-month periods ended September 30, 2003
compared to $2,900 and $10,000 for the same periods in 2002.

For the three-month and nine-month periods ended September 30, 2003, we
recorded a charge of $946,100 and $2.3 million, respectively, 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 charge of $107,100 and
$417,300, respectively, was recorded for the three-month and nine-month periods
ended September 30, 2002. This represents an estimated effective tax rate of
36.9% for the nine months ended September 30, 2002. Such rate was based on
anticipated results for the year ended December 31, 2002 using assumptions at
that time.

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

24

For the third quarter of 2003, we realized net income of $1.7 million,
or basic earnings per share of $0.18 and diluted earnings per share of $0.17.
This compares to a net income for the third quarter of 2002 of $156,300, or
basic and diluted earnings per share of $0.02. Weighted average shares
outstanding increased from 9.4 million shares for the three months ended
September 30, 2002 to 9.5 million shares in the comparable 2003 period. For the
nine months ended September 30, 2003, we realized net income of $3.8 million or
basic earnings per share of $0.40 and diluted earnings per share of $0.39
compared to net income of $713,400, or basic earnings per share of $0.08 and
diluted earnings per share of $0.07, for the comparable 2002 period. Weighted
average shares outstanding increased from 9.4 million for the nine months ended
September 30, 2002 to 9.5 million for the comparable 2003 period. The increase
in shares for both the three-month and nine-month periods 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 September 30, 2003 of $3.2 million
consisting primarily of short-term money market investments, as compared to $2.6
million at December 31, 2002. Working capital was $4.5 million as of September
30, 2003, as compared to $3.3 million at December 31, 2002.

Cash flows provided by operating activities for the nine months ended
September 30, 2003 totaled $16.3 million compared to $7.0 million for the nine
months ended September 30, 2002. The increase in cash flows provided by
operating activities in 2003 compared to 2002 was due to higher net income in
the 2003 period and lower working capital usage for the nine-month period ended
September 30, 2003 compared to the same period in 2002.

Cash used in investing activities totaled approximately $25.2 million
for the nine months ended September 30, 2003 compared to $15.0 million in the
same period of 2002. We expended $10.1 million in our drilling operations
resulting in the drilling of 28 gross (13.9 net) wells during the nine months
ended September 30, 2003 as compared to 13 gross (6.7 net) wells during the same
period in 2002. Since September 30, 2003, we have drilled 1 successful gross
well and 2 gross dry holes. Currently 3 gross wells are drilling. In addition to
capital expenditures for drilling operations for the 2003 period, approximately
$1.1 million was incurred on currently producing properties and $1.1 million was
expended on land and seismic activities. Acquisition costs totaled $11.6 million
for the 2003 period. The remaining costs capitalized to oil and natural gas
properties were internal G&A and interest of approximately $1.4 million and
other furniture and fixture costs of $204,200. We received proceeds of
approximately $330,100 during the nine months ended September 30, 2003 for the
sale of interests in certain oil and gas properties, including the sale of our
interest in the Essex I and Essex II joint ventures.

Cash flows provided by financing activities totaled $9.6 million for
the nine months ended September 30, 2003 and included $10.7 million in
borrowings, $(1.2) million in repayments of debt and $84,600 in proceeds from
the issuance of stock. For the comparable 2002 period, cash flow provided by
financing activities totaled $8.1 million and included $8.5 million of
borrowings from long-term debt, $(0.5) million in payments on long-term debt and
$52,100 in proceeds from the issuance of stock.

Due to our active exploration, development and acquisition activities,
we have experienced and expect to continue to experience substantial working
capital requirements. We intend to fund our 2003 capital expenditures,
commitments and working capital requirements through cash flows from operations,
and to the extent necessary other financing activities. The projected 2003 cash
flows from operations are estimated to be sufficient to fund our planned
exploration and development program. We do plan to use our credit facility to
fund, in whole or in part, acquisitions. Current usage of the credit facility is
$29.0 million. The pending merger with Miller Exploration announced in May 2003
is a stock for stock transaction that is expected to increase our resulting
liquidity as a result of Miller's expected positive working capital and lack of
debt. We expect to redetermine our existing borrowing base concurrent with the
shareholder vote to approve the Miller merger.

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

25

CREDIT FACILITY

During the nine months ended September 30, 2003, we borrowed $10.7
million and made repayments of $(1.2) million under our credit facility (the
"Credit Facility") and as of September 30, 2003, $30.0 million was outstanding
under the Credit Facility. Borrowings under the Credit Facility bear interest at
a rate equal to prime plus 0.50% or LIBOR plus 2.75%. We choose which interest
rate will be applied to a specific borrowing. The Credit Facility matures
January 2, 2005 and is secured by substantially all of our assets.

Effective September 30, 2003, the borrowing base was increased to
$32.0 million as a result of the acquisition of properties in South Texas and
our drilling activities since the last redetermination. The borrowing base is
not subject to automatic reductions at this time. We expect to redetermine our
existing borrowing base concurrent with the shareholder vote to approve the
Miller merger.

The Credit Facility provides for certain restrictions, including but
not limited to, limitations on additional borrowings and issues of capital
stock, sales of oil and natural gas properties or other collateral, and engaging
in merger or consolidation transactions. The Credit Facility also prohibits
dividends and certain distributions of cash or properties and certain liens. The
Credit Facility also contains certain financial covenants. The EBITDA to
Interest Expense Ratio requires that (a) our consolidated EBITDA, as defined in
the agreement, for the four fiscal quarters then ended to (b) our consolidated
interest expense for the four fiscal quarters then ended, to not be less than
3.5 to 1.0. EBITDA was part of a negotiated covenant with our lender and is
presented here to define our requirements to comply with that covenant. The
Working Capital ratio requires that the amount of our consolidated current
assets less our consolidated liabilities, as defined in the agreement, be at
least $1.0 million. The Allowable Expenses ratio requires that (a) the aggregate
amount of our year-to-date consolidated general and administrative expenses for
the period from January 1 of such year through the fiscal quarter then ended to
(b) our year-to-date consolidated oil and gas revenue, net of hedging activity,
for the period from January 1 of such year through the fiscal quarter then
ended, to be less than 0.40 to 1.0. At September 30, 2003, we were in compliance
with the above-mentioned covenants.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

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

A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and 142 to companies in the extractive industries,
including oil and gas companies. The issue is whether SFAS No. 141 requires
registrants to classify the costs of mineral rights associated with extracting
oil and gas as intangible assets in the balance sheet, apart from other
capitalized oil and gas property costs, and provide specific footnote
disclosures. Historically, we have included the costs of mineral rights
associated with extracting oil and gas as a component of oil and gas properties.
If it is ultimately determined that SFAS No. 141 requires oil and gas companies
to classify costs of mineral rights associated with extracting oil and gas as a
separate intangible assets line item on the balance sheet, we would be required
to reclassify approximately $21.4 million and $8.8 million at September 30, 2003
and December 31, 2002, respectively, out of oil and gas properties and into a
separate intangible assets line item. These costs include those to acquire
contract based drilling and mineral use rights such as delay rentals, lease
bonuses, commissions and brokerage fees, and other leasehold costs. Our
Company's cash flows and results of operations would not be affected since such
intangible assets would continue to be depleted and assessed for impairment in
accordance with full cost accounting rules, as allowed by SFAS No. 142. Further,
we do not believe the classification of the costs of mineral rights associated
with extracting oil and gas as intangible assets would have any impact on our
compliance with covenants under our debt agreements.

26

In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts
(collectively referred to as derivatives) and for hedging activities under SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities". SFAS
No. 149 is effective for contracts entered into or modified after June 30, 2003.
This statement did not impact us for the nine-month period ended September 30,
2003.

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

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

We share interests with related parties in a variety of different
partnership and joint venture entities in order to share the rewards of
ownership in certain oil and natural gas royalties. We do not provide
supplemental financial support to these entities. In general, these entities are
structured such that the voting and sharing ratios in these entities are
consistent with the allocation of the entities' distributions of cash from
royalty revenues. We do not anticipate that we will be impacted by FIN 46
because there is no investment in or obligation to share in future capital
requirements of these entities.

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

HEDGING ACTIVITIES

Due to the volatility 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 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.

27

In August 2003, we purchased natural gas options that cover 10,000
MMbtus per day for the period January 1, 2004 to December 31, 2004 at a floor of
$4.50 per MMbtu and a ceiling of $7.00 per MMbtu for the first and fourth
quarters of 2004 and $6.00 per MMbtu for the second and third quarters of 2004
for a cost of $686,250. At September 30, 2003 the market value of this
instrument was approximately $1.0 million and is included in current assets.

In April 2003, we entered into a natural gas collar covering 2,000
MMbtu per day for the period June 1, 2003 to September 30, 2003 with a floor of
$5.00 per MMbtu and a ceiling of $6.50 per MMbtu. The natural gas collar expired
with no additional cost to us.

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 September 30,
2003, the market value of this outstanding hedge was a loss of approximately
$(0.5) million and is included in current assets.

In August 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 and 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.

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

TAX MATTERS

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

28

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 our acquisitions and 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 September 30, 2003 outstanding
borrowings and a floating interest rate of 3.66%, a 10% change in interest rates
would result in an increase or decrease of interest expense of approximately
$104,800 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. At September 30, 2003, the net
fair value of all outstanding hedges was approximately $0.5 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 $1.4 million.

ITEM 4. CONTROLS AND PROCEDURES

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

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

FORWARD LOOKING STATEMENTS

The statements contained in all parts of this document, including, but
not limited to, those relating to the timing and effects of the proposed merger
with Miller Exploration Company and our acquisition of properties in South Texas
(including any expectations regarding increases in our liquidity or available
credit), our ability to access the capital markets to raise additional capital,
our drilling plans, our 3-D project portfolio, capital expenditures, future
capabilities, the sufficiency of capital resources and liquidity to support
working capital and capital expenditure requirements, reinvestment of cash
flows, use of NOLs, tax rates, the outcome of litigation, and any other
statements regarding future operations, financial results, business plans,
sources of liquidity and cash needs and other statements that are not historical
facts are forward looking statements. When used in this document, the words
"anticipate," "estimate," "expect," "may," "project," "believe" and similar
expressions are intended to be among the statements that identify forward
looking statements. Such statements involve risks and uncertainties, including,
but not limited to, those relating to the results of and our dependence on our
exploratory drilling activities, the volatility of oil and natural gas prices,
the need to replace reserves depleted by production, operating risks of oil and
natural gas operations, our dependence on key personnel, our reliance on
technological development and 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, the
qualification of entities of variable interest entities under FIN 46, results of
litigation, our ability to manage our growth and achieve our business strategy,
competition from larger oil and gas

29

companies, the uncertainty of reserve information and future net revenue
estimates, property acquisition risks and other factors detailed in our Form
10-K/A 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 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 the Company, could have a
potential material adverse effect on our financial condition, results of
operations or cash flows.

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

30

to the Company's Quarterly Report on Form 10-Q for the
quarterly period ended September 31, 2000).

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

+4.3 -- Amendment No. 2 dated as of May 29, 2002 by and among the
lenders party to the Second Amended and Restated Credit
Agreement dated October 6, 2000 ("Lenders"), Union Bank of
California, N.A., a national banking association, as agent for
such Lenders, Edge Petroleum Corporation, Edge Petroleum
Exploration Company, and Edge Petroleum Operating Company,
Inc. (collectively, the "Borrowers"), as borrowers under the
Second Amended and Restated Credit Agreement. (Incorporated by
reference from exhibit 4.3 to the Company's Annual Report on
Form 10-K/A for the year ended December 31, 2002).

+4.4 -- Amendment No. 3 dated as of August 8, 2002 by and among the
lenders party to the Second Amended and Restated Credit
Agreement dated October 6, 2000 ("Lenders"), Union Bank of
California, N.A., a national banking association, as agent for
such Lenders, Edge Petroleum Corporation, Edge Petroleum
Exploration Company, and Edge Petroleum Operating Company,
Inc. (collectively, the "Borrowers"), as borrowers under the
Second Amended and Restated Credit Agreement. (Incorporated by
reference from exhibit 4.4 to the Company's Annual Report on
Form 10-K/A for the year ended December 31, 2002).

+4.5 -- Amendment No. 4 dated as of April 21, 2003 by and among the
lenders party to the Second Amended and Restated Credit
Agreement dated October 6, 2000 ("Lenders"), Union Bank of
California, N.A., a national banking association, as agent for
such Lenders, Edge Petroleum Corporation, Edge Petroleum
Exploration Company, and Edge Petroleum Operating Company,
Inc. (collectively, the "Borrowers"), as borrowers under the
Second Amended and Restated Credit Agreement (Incorporated by
reference from exhibit 4.5 to the Company's Quarterly Report
on Form 10-Q for the quarter ended June 30, 2003).

*4.6 -- Amendment No. 5 dated as of September 30, 2003 by and among
the lenders party to the Second Amended and Restated Credit
Agreement dated October 6, 2000 ("Lenders"), Union Bank of
California, N.A., a national banking association, as agent for
such Lenders, Edge Petroleum Corporation, Edge Petroleum
Exploration Company, and Edge Petroleum Operating Company,
Inc. (collectively, the "Borrowers"), as borrowers under the
Second Amended and Restated Credit Agreement.

+4.7 -- 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).

+4.8 -- 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 10-K for the annual period ended
December 31, 2000).

+4.9 -- 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 10-Q for the quarterly period ended
September 30, 2001).

+4.10 -- 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 10-K for the annual period ended
December 31, 2001).

+4.11 -- 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 10-Q for the quarterly period ended
June 30, 2002).

+4.12 -- 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).

31

+4.13 -- 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).

+4.14 -- 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 10.3 to the Company's Annual Report on
Form 10-K/A 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 10.4 to the Company's Annual Report on
Form 10-K/A for the year ended December 31, 2002).

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

32

reference from exhibit 10.3 to the Company's Quarterly Report
on Form 10-Q for the quarterly period ended September 30,
1999).

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

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

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

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

*31.1 -- Certification by John W. Elias, Chief Executive Officer,
pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the
Securities Exchange Act of 1934.

*31.2 -- Certification by Michael G. Long , Chief Financial and
Accounting Officer, pursuant to Rule 13a-14(a) or Rule
15d-14(a) under the Securities Exchange Act of 1934.

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

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

* Filed herewith.
+ Incorporated by reference as indicated.

(B) Reports on Form 8-K ..........................................

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

The Company filed a Current Report on Form 8-K on August 1, 2003
(information furnished not filed) announcing the issuance of a press release
announcing the entering into an agreement with respect to the acquisition of
properties in South Texas and attaching a copy of the press release as an
exhibit.

The Company filed a Current Report on Form 8-K on August 4, 2003
(information furnished not filed) announcing the issuance of a press release
announcing updated information regarding the merger with Miller Exploration
Company and attaching a copy of the press release as an exhibit.

The Company filed a Current Report on Form 8-K on August 6, 2003
(information furnished not filed) announcing the issuance of a press release
reporting 2003 second quarter financial results update and attaching a copy of
the press release as an exhibit.

The Company filed a Current Report on Form 8-K on September 2, 2003
(information furnished not filed) announcing it had entered into an exploration
agreement in Southeast New Mexico.

33

The Company filed a Current Report on Form 8-K on September 5, 2003
(information furnished not filed) announcing the issuance of a press release
reporting increased capital spending and operating activities for 2003 and
attaching a copy of the press release as an exhibit.

The Company filed a Current Report on Form 8-K on September 19, 2003
(information furnished not filed) announcing its presentation at the Johnson
Rice Conference and attaching a copy of the related slide presentation.

34

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 11/14/2003 /S/ John W. Elias
- ------------------------- --------------------------------------------
John W. Elias
Chief Executive Officer and
Chairman of the Board

Date 11/14/2003 /S/ Michael G. Long
- ------------------------- --------------------------------------------
Michael G. Long
Senior Vice President and
Chief Financial and Accounting Officer

35

INDEX TO EXHIBITS

36

+4.5 -- Amendment No. 4 dated as of April 21, 2003 by and among the
lenders party to the Second Amended and Restated Credit
Agreement dated October 6, 2000 ("Lenders"), Union Bank of
California, N.A., a national banking association, as agent for
such Lenders, Edge Petroleum Corporation, Edge Petroleum
Exploration Company, and Edge Petroleum Operating Company,
Inc. (collectively, the "Borrowers"), as borrowers under the
Second Amended and Restated Credit Agreement (Incorporated by
reference from exhibit 4.5 to the Company's Quarterly Report
on Form 10-Q for the quarter ended June 30, 2003).

*4.6 -- Amendment No. 5 dated as of September 30, 2003 by and among
the lenders party to the Second Amended and Restated Credit
Agreement dated October 6, 2000 ("Lenders"), Union Bank of
California, N.A., a national banking association, as agent for
such Lenders, Edge Petroleum Corporation, Edge Petroleum
Exploration Company, and Edge Petroleum Operating Company,
Inc. (collectively, the "Borrowers"), as borrowers under the
Second Amended and Restated Credit Agreement.

+4.7 -- 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).

+4.8 -- 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 10-K for the annual period ended
December 31, 2000).

+4.9 -- 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 10-Q for the quarterly period ended
September 30, 2001).

+4.10 -- 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 10-K for the annual period ended
December 31, 2001).

+4.11 -- 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 10-Q for the quarterly period ended
June 30, 2002).

+4.12 -- 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).

+4.13 -- 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).

+4.14 -- 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

37

from exhibit 10.3 to the Company's Annual Report on Form
10-K/A 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 10.4 to the Company's Annual Report on
Form 10-K/A for the year ended December 31, 2002).

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

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

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

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

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

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

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

*31.1 -- Certification by John W. Elias, Chief Executive Officer,
pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the
Securities Exchange Act of 1934.

*31.2 -- Certification by Michael G. Long , Chief Financial and
Accounting Officer, pursuant to Rule 13a-14(a) or Rule
15d-14(a) under the Securities Exchange Act of 1934.

38

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

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

* Filed herewith.
+ Incorporated by reference as indicated.

39