UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2004

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

For the transition period from to

Commission file number 0-22149

EDGE PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

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

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

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

Class		Outstanding at August 9, 2004

Common Stock		12,993,308

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EDGE PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

	June 30, 2004			December 31, 2003
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,733,450		$	1,327,081
Accounts receivable, trade, net of allowance of $525,248 at June 30, 2004 and December 31, 2003	10,460,034			8,889,734
Accounts receivable, joint interest owners, net of allowance of $82,000 at June 30, 2004 and December 31, 2003	2,062,619			1,797,877
Deferred tax asset	1,246,843			1,138,492
Derivative financial instruments	325,965			120,801
Other current assets	2,133,166			1,186,987
Total current assets	19,962,077			14,460,972
PROPERTY AND EQUIPMENT, Net – full cost method of accounting for oil and natural gas properties (including unevaluated costs of $5.5 million and $5.0 million at June 30, 2004 and December 31, 2003, respectively)	107,033,609			97,980,757
DEFERRED TAX ASSET	2,144,334			5,570,137
OTHER ASSETS	351,920			—
TOTAL ASSETS	$	129,491,940		$	118,011,866

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable, trade	$	2,710,732		$	1,732,935
Accrued liabilities	13,270,047			11,456,036
Accrued interest	20,573			—
Asset retirement obligation	386,889			323,513
Derivative financial instruments	560,952			—
Total current liabilities	16,949,193			13,512,484
ASSET RETIREMENT OBLIGATION	1,504,208			1,488,482
LONG-TERM DEBT	18,000,000			21,000,000
Total liabilities	36,453,401			36,000,966
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY
Preferred stock, $0.01 par value; 5,000,000 shares authorized; none issued and outstanding	—			—
Common stock, $0.01 par value; 25,000,000 shares authorized; 12,972,284 and 12,581,032 shares issued and outstanding at June 30, 2004 and December 31, 2003, respectively	129,723			125,810
Additional paid-in capital	79,379,264			75,282,007
Retained earnings	14,105,874			6,966,557
Accumulated other comprehensive loss	(576,322		)	(363,474		)
Total stockholders’ equity	93,038,539			82,010,900
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	129,491,940		$	118,011,866

See accompanying notes to consolidated financial statements.

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
OIL AND NATURAL GAS REVENUE	$	15,847,404		$	7,994,395		$	31,662,061		$	14,833,165
OPERATING EXPENSES:
Lease operating expenses	1,220,092			550,998			2,425,166			1,145,802
Severance and ad valorem taxes	1,210,208			521,904			2,254,922			1,041,059

Depletion, depreciation, amortization and accretion	5,141,387			2,859,336			10,383,802			5,607,209
General and administrative expenses:
Deferred compensation – repriced options	337,386			—			1,448,485			—
Deferred compensation – restricted stock	114,600			89,775			211,100			176,439
Other general and administrative expenses	1,731,453			1,430,756			3,632,280			2,687,018
Total operating expenses	9,755,126			5,452,769			20,355,755			10,657,527
OPERATING INCOME	6,092,278			2,541,626			11,306,306			4,175,638
OTHER INCOME AND EXPENSE:
Interest income	4,023			3,025			8,031			5,148
Interest expense, net of amounts capitalized	(105,405		)	(165,046		)	(219,683		)	(341,435		)
Amortization of deferred loan costs	(40,748		)	—			(70,384		)	—
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE	5,950,148			2,379,605			11,024,270			3,839,351
INCOME TAX EXPENSE	(2,094,067		)	(845,471		)	(3,884,953		)	(1,367,193		)
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE	3,856,081			1,534,134			7,139,317			2,472,158
CUMULATIVE EFFECT OF ACCOUNTING CHANGE	—			—			—			(357,825		)
NET INCOME	3,856,081			1,534,134			7,139,317			2,114,333
OTHER COMPREHENSIVE INCOME (LOSS), net of taxes:
Unrealized hedge derivative fair value gain (loss)	563,039			(10,610		)	(368,047		)	(860,727		)
Reclassification to earnings of realized (gain) loss upon settlement of hedge derivative contracts	(208,275		)	165,814			155,199			446,375
Other comprehensive income (loss)	354,764			155,204			(212,848		)	(414,352		)
COMPREHENSIVE INCOME	$	4,210,845		$	1,689,338		$	6,926,469		$	1,699,981
BASIC EARNINGS PER SHARE:
Income before cumulative effect of accounting change	$	0.30		$	0.16		$	0.56		$	0.26
Cumulative effect of accounting change	—			—			—			(0.04		)
Net income per share	$	0.30		$	0.16		$	0.56		$	0.22
DILUTED EARNINGS PER SHARE:
Income before cumulative effect of accounting change	$	0.28		$	0.16		$	0.53		$	0.26
Cumulative effect of accounting change	—			—			—			(0.04		)
Net income per share	$	0.28		$	0.16		$	0.53		$	0.22
BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING	12,940,504			9,502,255			12,833,226			9,471,227
DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING	13,588,578			9,709,192			13,412,589			9,641,851

See accompanying notes to consolidated financial statements.

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

	Six Months Ended June 30,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	7,139,317		$	2,114,333
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of accounting change	—			357,825
Change in the fair value of derivative instruments	(179,261		)	—
Deferred income taxes	3,884,953			1,367,193
Depletion, depreciation, amortization and accretion	10,383,802			5,607,209
Amortization of deferred loan costs	70,384			—
Deferred compensation	1,659,585			176,439
Changes in assets and liabilities:
Increase in accounts receivable, trade	(1,356,450		)	(2,385,505		)
Increase in accounts receivable, joint interest owners	(264,742		)	(50,498		)
Increase in other assets	(946,179		)	(509,858		)
Increase (decrease) in accounts payable, trade	977,797			(775,242		)
Increase in accrued liabilities	1,857,593			2,446,177
Increase in accrued interest payable	20,573			41,634
Net cash provided by operating activities	23,247,372			8,389,707

CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property and equipment additions	(19,397,552		)	(7,649,966		)
Proceeds from the sale of oil and natural gas properties	40,000			55,096
Net cash used in investing activities	(19,357,552		)	(7,594,870		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from long-term debt	—			1,700,000
Payments of long-term debt	(3,000,000		)	(1,200,000		)
Net proceeds from issuance of common stock	1,938,853			53,499
Deferred loan costs	(422,304		)	—
Net cash provided by (used in) financing activities	(1,483,451		)	553,499
NET INCREASE IN CASH AND CASH EQUIVALENTS	2,406,369			1,348,336
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	1,327,081			2,568,176
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	3,733,450		$	3,916,512

See accompanying notes to consolidated financial statements.

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

				Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
	Common Stock
	Shares	Amount
BALANCE, DECEMBER 31, 2003	12,581,032	$	125,810	$	75,282,007	$	6,966,557	$	(363,474	)	$	82,010,900
Issuance of common stock	391,252	3,913		1,978,522		—		—			1,982,435
Deferred compensation - restricted stock	—	—		211,100		—		—			211,100
Deferred compensation - repriced options	—	—		1,448,485		—		—			1,448,485
Change in valuation of hedging instruments	—	—		—		—		(212,848		)	(212,848		)
Tax benefit associated with exercise of non-qualified stock options	—	—		459,150		—		—			459,150
Net income	—	—		—		7,139,317		—			7,139,317
BALANCE, June 30, 2004	12,972,284	$	129,723	$	79,379,264	$	14,105,874	$	(576,322	)	$	93,038,539

See accompanying notes to consolidated financial statements.

EDGE PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The financial statements included herein have been prepared by Edge Petroleum Corporation, a Delaware corporation (“we”, “our”, “us” or the “Company”), without audit pursuant to the rules and regulations of the Securities and Exchange Commission (“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 for the year ended December 31, 2003.

Oil and Natural Gas Properties - Investments in oil and natural gas properties are accounted for using the full cost method of accounting. All costs associated with the exploration, development and acquisition of oil and natural gas properties, including salaries, benefits and other internal costs directly attributable to these activities are capitalized within a cost center. 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 $5.5 million and $5.0 million at June 30, 2004 and December 31, 2003, respectively, related to unevaluated property, 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 and dismantlement costs, and restoration and abandonment costs, net of estimated salvage values.

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, asset retirement obligation 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. In accordance with Staff Accounting Bulletin (“SAB”) No.103, “Update of Codification of Staff Accounting Bulletins,” derivative instruments qualifying as cash flow hedges are included in the computation of limitation on capitalized costs. The period end price exceeded the cap established by one of the Company’s hedges at June 30, 2004 and thus a $284,000 reduction to the limitation threshold was used in this calculation. No impairment related to the ceiling test was required during the six-month periods ended June 30, 2004 or 2003.

In March 2004, the Emerging Issues Task Force (“EITF”) reached a consensus that mineral rights, as defined in EITF Issue No. 04-2, “Whether Mineral Rights Are Tangible or Intangible Assets,” are tangible assets and that they should be removed as examples of intangible assets in SFAS Nos. 141 and 142. The FASB has recently ratified this consensus and directed the FASB staff to amend SFAS Nos. 141 and 142 through the issuance of FASB Staff Positions FSP FAS 141-1 and FSP FAS 142-1. In addition, proposed FSP FAS 142-b confirms that SFAS No. 142 does not change the balance sheet classification or disclosures of mineral rights of oil and gas producing enterprises. Historically, we have included the costs of such mineral rights as tangible assets, which is consistent with the EITF’s consensus. As such, EITF 04-2 and the related FSPs have not affected our consolidated financial statements.

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.

Asset Retirement Obligations – 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 is increased. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.

At January 1, 2003, the Company recorded the present value of its future Asset Retirement Obligations (“ARO”) for oil and natural gas properties 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 periods ended June 30, 2004 and 2003 are as follows:

	Six Months Ended June 30,
	2004			2003
ARO, Beginning of Period	$	1,811,995		$	942,736
Liabilities incurred in the current period	139,737			63,487
Liabilities settled in the current period	(113,136		)	—
Accretion expense	52,501			29,853
Revisions	—			(9,714		)
ARO, End of Period	$	1,891,097		$	1,026,362

ARO liabilities incurred during the six months ended June 30, 2004 include obligations for 18 new wells drilled during the first half of the year. Liabilities settled during the six months ended June 30, 2004 included seven wells that were plugged and one well that was sold.

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 and earnings per share would have been as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Net income as reported	$	3,856,081		$	1,534,134		$	7,139,317		$	2,114,333
Add:
Stock-based employee compensation expense included in reported net income, net of related income tax	293,791			31,421			1,078,730			61,753
Deduct:
Total stock-based employee compensation expense determined under fair value based method for all awards, net of related income tax	(90,111		)	(87,934		)	(208,288		)	(176,075		)
Pro forma net income	$	4,059,761		$	1,477,621		$	8,009,759		$	2,000,011

Earnings Per Share:
Basic – as reported	$	0.30		$	0.16		$	0.56		$	0.22
Basic – pro forma	$	0.31		$	0.16		$	0.62		$	0.21

Diluted – as reported	$	0.28		$	0.16		$	0.53		$	0.22
Diluted – pro forma	$	0.30		$	0.15		$	0.60		$	0.21

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. A pre-tax charge of $1.4 million was required for the six months ended June 30, 2004. No charge related to FIN 44 was required during the six-month period ended June 30, 2003.

Accounting Pronouncements – In March 2004, the FASB issued an exposure draft entitled “Share-Based Payment, an Amendment of FASB Statement No. 123 and 95.” This proposed statement addresses the accounting for share-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may be settled by the issuance of such equity instruments. The proposed statement would eliminate the ability to account for share-based compensation transactions using APB Opinion No. 25, “Accounting for Stock Issued to Employees”, and generally would require instead that such transactions be accounted for using a fair-value-based method. As proposed, this statement would be effective for the Company on January 1, 2005. The impact on the results of operations would be similar to the pro forma disclosures made above.

2. LONG TERM DEBT

Effective December 31, 2003, the Company entered into a new amended and restated credit facility (the “Credit Facility”) which permits borrowings up to the lesser of (i) the borrowing base or (ii) $100 million. Borrowings under the Credit Facility bear interest at a rate equal to prime plus 0.50% or LIBOR plus 2.25%. As of June 30, 2004, $18.0 million in borrowings were outstanding under the Credit Facility. The Credit Facility matures December 31, 2006 and is secured by substantially all of the Company’s assets.

Effective June 8, 2004, the borrowing base under the Credit Facility was increased to $45.0 million from $40.0 million; primarily as a result of our drilling activities since the last redetermination. At June 30, 2004, the Company’s available borrowing capacity under this facility was $27.0 million.

The Credit Facility provides for certain restrictions, including but not limited to, limitations on additional borrowings, 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 the following financial covenants, among others:

• The EBITDAX to Interest Expense ratio requires that (a) consolidated EBITDAX (defined as EBITDA plus similar non-cash items and exploration and abandonment expenses for such period) of the Company for the four fiscal quarters then ended to (b) the consolidated interest expense of the Company for the four fiscal quarters then ended, not be less than 3.5 to 1.0.

• The Working Capital ratio requires that the amount of the Company’s consolidated current assets less its consolidated current liabilities, as defined in the agreement, be at least $1.0 million.

At June 30, 2004, the Company was in compliance with the above-mentioned covenants. EBITDA and EBITDAX were part of a negotiated covenant with our lender and are presented here as disclosure of our compliance with that covenant.

3. SHELF REGISTRATION STATEMENT

The Company filed a $150 million shelf registration statement, which became effective in May 2004. Under the shelf registration statement, the Company may issue, from time to time, any combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities in one or more offerings to those persons who agree to purchase our securities. At June 30, 2004, the Company had $150 million remaining for issuance under the shelf registration. The Company has no immediate plans to issue equity securities, however the Company will continue to explore opportunities in 2004 to replace existing debt and otherwise access capital through issuances of debt securities under this registration statement. Our ability to utilize the shelf registration statement will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices and terms acceptable to us.

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 common 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 common share computations, in accordance with SFAS No. 128, for the three-month and six-month periods ended June 30, 2004 and 2003:

	Three Months Ended June 30, 2004						Three Months Ended June 30, 2003
	Income (Numerator)		Shares (Denominator)	Per Share Amount			Income (Numerator)		Shares (Denominator)	Per Share Amount
Basic EPS
Income available to common stockholders	$	3,856,081	12,940,504	$	0.30		$	1,534,134	9,502,255	$	0.16
Effect of dilutive securities:
Restricted stock	—		138,138	(0.01		)	—		106,129	—
Common stock options	—		509,936	(0.01		)	—		100,808	—
Diluted EPS
Income available to common stockholders	$	3,856,081	13,588,578	$	0.28		$	1,534,134	9,709,192	$	0.16

	Six Months Ended June 30, 2004						Six Months Ended June 30, 2003
	Income (Numerator)		Shares (Denominator)	Per Share Amount			Income (Numerator)		Shares (Denominator)	Per Share Amount
Basic EPS
Income available to common stockholders	$	7,139,317	12,833,226	$	0.56		$	2,114,333	9,471,227	$	0.22
Effect of dilutive securities:
Restricted stock	—		105,368	(0.01		)	—		101,080	—
Common stock options	—		473,995	(0.02		)	—		69,544	—
Diluted EPS
Income available to common stockholders	$	7,139,317	13,412,589	$	0.53		$	2,114,333	9,641,851	$	0.22

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, 2004 will be approximately 35.2%. A provision for income taxes of $3.9 million and $1.4 million was reported for the six months ended June 30, 2004 and 2003, respectively. The Company was not required to pay income taxes in 2003 or 2002 because of the utilization net operating loss carryforwards.

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

The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. A summary of non-cash investing and financing activities for the six months ended June 30, 2004 and 2003 is presented below:

Description	Number of shares issued	Fair Market Value
Six months ended June 30, 2004:
Shares issued to satisfy restricted stock grants	56,136	$	354,183
Shares issued to fund the Company’s matching contribution under the Company’s 401 (k) plan	3,360	$	43,582
Six months ended June 30, 2003:
Shares issued to satisfy restricted stock grants	73,962	$	390,238
Shares issued to fund the Company’s matching contribution under the Company’s 401 (k) plan	7,800	$	31,307

For the six months ended June 30, 2004 and 2003, the non-cash portion of Asset Retirement Costs was $26,601 and $789,066.

Supplemental Disclosure of Cash Flow Information

	For the Six Months Ended June 30,
	2004		2003
Cash paid during the period for:
Interest, net of amounts capitalized	$	199,109	$	172,103

Interest paid for the six months ended June 30, 2004 and 2003 excludes amounts capitalized of $211,479 and $124,012, respectively. The Company was not required to pay 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. None of these instruments are used for trading purposes. The Company’s hedging arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit the Company’s potential gains from future increases in prices. The Company’s management 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 Board of Directors reviews the Company’s hedge policies and trades. In accordance with SFAS No. 133, all derivative contracts are recorded on the balance sheet at fair value. The Company accounts for natural gas contracts as hedges of future cash flows from sale of natural gas. Accordingly, the effective portion of the changes in the fair value of the natural gas contracts are recorded in other comprehensive income. When the hedged production is sold, the realized gains and losses on the natural gas contracts are removed from other comprehensive income and recorded in oil and natural gas revenue. Ineffective portions of the changes in fair value of the natural gas contracts are recognized in oil and natural gas revenue as they occur. While the hedge contract is outstanding, the ineffective gain or loss may increase or decrease until settlement of the contract. There was no ineffectiveness recognized during the six months ended June 30, 2004 or 2003. For those derivative contracts that either do not qualify for hedge accounting or the Company does not designate as hedges of future cash flows, the changes in fair value are not deferred through other comprehensive income, but rather recorded in oil and natural gas revenue immediately.

For the six months ended June 30, 2004 and 2003, the Company included in other oil and natural gas revenues realized and unrealized losses of $0.4 million and $3.3 million, respectively, related to its natural gas hedges and oil derivatives.

	Six Months Ended June 30,
	2004			2003
Natural gas hedging contract settlements	$	(222,000	)	$	(3,335,880	)
Oil derivative contract settlements	(103,276		)	—
Hedge premium reclassification	(213,850		)	—
Non-qualified derivative contracts	179,261			—
	$	(359,865	)	$	(3,335,880	)

The Company did not apply hedge accounting to its crude oil collars entered into in March and May of 2004, because although they were economic hedges, they did not qualify for hedge accounting.

The outstanding derivatives and hedges at June 30, 2004 and December 31, 2003 impacting the balance sheet were as follows:

							Unrealized Hedging Gains (Losses) As of
Transaction Date	Transaction Type		Beginning	Ending	Price Per Unit	Volumes Per Day	June 30, 2004			December 31, 2003
*Natural Gas:*
12/03	Natural Gas Collar	(1)	1/1/04	3/31/04	$4.50-$7.05	5,000	$	—		$	37,688
08/03	Natural Gas Collar	(1) (2)	4/1/04	9/30/04	$4.50-$6.00	10,000	(212,300		)	42,996
08/03	Natural Gas Collar	(1) (2)	1/1/04 10/1/04	3/31/04 12/31/04	$4.50-$7.00	10,000	(240,104		)	40,117
02/04	Natural Gas Collar	(1)	4/1/04	9/30/04	$4.50-$6.20	5,000	(70,410		)	—
*Crude Oil:*
05/04	Crude Oil Collar	(3)	1/1/05	12/31/05	$30.00-$39.15	200	(38,138		)	—
							$	(560,952	)	$	120,801

*Natural Gas:*
03/04	Natural Gas Collar	(1)	10/1/04	12/31/04	$4.50-$7.25	5,000	116,849			—
05/04	Natural Gas Collar	(1)	1/1/05	03/31/05	$5.00-$10.39	10,000	(8,283		)	—
*Crude Oil:*
03/04	Crude Oil Collar	(3)	4/1/04	12/31/04	$30.00-$35.50	400	217,399			—
							$	325,965		$	—

(1) The Company’s current hedging activities for natural gas were entered into on a per MMbtu delivered price basis, using the Houston Ship Channel Index, with settlement for each calendar month occurring five business days following the expiration date.

(2) This hedge was entered into at a cost of $686,250.

(3) Hedge accounting is not applied to the Company’s collars on crude oil, which were entered into on a per barrel delivered price basis, using the West Texas Intermediate Index, with settlement for each calendar month occurring five business days following the expiration date. The change in fair value is reflected in net revenue for the six months ended June 30, 2004.

Hedges entered into after June 30, 2004 were as follows:

Transaction Date	Hedge Type	Effective Dates		Price Per Unit	Volume Per Day
Transaction Date	Hedge Type	Beginning	Ending	Price Per Unit	Volume Per Day
07/04	Natural Gas Collar (1)	4/1/05	6/30/05	$5.00-$7.53	10,000 MMBTU
07/04	Natural Gas Collar (1)	7/1/05	9/30/05	$5.00-$7.67	10,000 MMBTU

(1) The Company’s current hedging activities for natural gas were entered into on a per MMbtu delivered price basis, Houston Ship Channel Index, with settlement for each calendar month occurring five business days following the expiration date.

8. MILLER EXPLORATION COMPANY MERGER

On December 4, 2003, Edge acquired 100% of the outstanding common stock of Miller Exploration Company (“Miller”) in a transaction pursuant to which Miller became a wholly-owned subsidiary of Edge. The acquisition of Miller was accounted for using the purchase method of accounting.

The following unaudited pro forma financial information has been prepared to present the combined results of Edge and Miller for the six months ended June 30, 2003, as if the merger had occurred at the beginning of the period presented. This unaudited pro forma consolidated statement of operations data does not include adjustments to reflect any cost savings or other operational efficiencies that may be realized as a result of the merger of Edge and Miller, or any future merger-related restructuring or integration expenses. The pro forma data presented is based on numerous assumptions and is not necessarily indicative of future results of operations of the merged companies.

	Six Months Ended June 30, 2003
	(In thousands, except per share data)
STATEMENT OF OPERATIONS DATA
Oil and natural gas revenue	$	20,806
Income before cumulative effect of accounting change	$	4,017
Basic earnings per share before cumulative effect of accounting change	$	0.33
Diluted earnings per share before cumulative effect of accounting change	$	0.33

9. 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.

During the second quarter of 2004, the Company received notice that its franchise tax returns for the State of Texas would be audited for the tax years 1999 through 2002. After reviewing documents submitted, the agent representing the Office of the Comptroller of the State of Texas proposed adjustments to the calculation that would result in an increased franchise tax liability. The agent maintains that transfers by the parent company to its subsidiaries that the Company classified as intercompany loans should instead be classified as equity investments in the subsidiary. If the State of Texas prevails in this assertion, the franchise tax liability of the subsidiaries would be increased by approximately $3.0 million for the four-year period under audit.

At this time, the Company is in preliminary discussions with the agent. The Company believes its practice is correct and is vigorously contesting this matter. Should the Company’s negotiations with the agent prove unsuccessful, the Company plans to file an administrative protest of these adjustments and begin the appeals process.

The Company intends to vigorously contest the proposed adjustments and has not recognized any provision for the additional franchise tax that would result from the proposed deficiency.

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 Management’s Discussion and Analysis of Financial Condition and Results of Operations and our audited consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2003.

FORWARD LOOKING STATEMENTS

The statements contained in all parts of this document, including, but not limited to, those relating to our outlook, the effects of the 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 audits, 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,” “budgeted,” “intend,” “plan,” “potential,” “forecast,” “might,” “predict,” “should” 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 and development drilling activities, the volatility of oil and natural gas prices, the need to replace reserves depleted by production, operating risks of oil and natural gas operations, our dependence on key personnel, our reliance on technological development and possible obsolescence of the technology currently used by us, the significant capital requirements of our exploration and development and technology development programs, the potential impact of government regulations and liability for environmental matters, results of litigation and audits, expansion of our capital budgets, our ability to manage our growth and achieve our business strategy, competition from larger oil and gas companies, the uncertainty of reserve information and future net revenue estimates, property acquisition risks and other factors detailed in our Form 10-K and other filings with the Securities and Exchange Commission (“SEC”). Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to the Company or the persons acting on its behalf are expressly qualified in their entirety by the reference to these risks and uncertainties.

GENERAL OVERVIEW

Edge Petroleum Corporation is a Houston-based independent energy company that focuses its exploration, production and marketing activities in selected onshore basins of the United States.

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 undertook a top-level management change late in 1998 and began a shift in strategy from pure exploration which focused more on prospect generation to our current strategy which focuses on a balanced program of exploration, exploitation and development and acquisition of oil and gas properties.

In December 2003, we acquired 100 percent of the outstanding stock of Miller Exploration Company (“Miller”). The transaction was treated as a tax-free reorganization and accounted for as a purchase business

combination. In the merger, we issued approximately 2.6 million shares of Edge common stock using a ratio of 1.22342 Edge shares for each share of Miller common stock outstanding. Miller continues to conduct exploration and development activities as a wholly-owned subsidiary of Edge.

Industry and Economic Factors

In managing our business, we must deal with many factors inherent in our industry. First and foremost is the fluctuation of oil and gas prices. Historically, oil and gas markets have been cyclical and volatile, with future price movements difficult to predict. While our revenues are a function of both production and prices, wide swings in commodity prices have most often had the greatest impact on our results of operations.

Our operations entail significant complexities. Advanced technologies requiring highly trained personnel are utilized in both exploration and production. Even when the technology is properly used, we may still not know conclusively if hydrocarbons will be present or the rate at which they will be produced. Exploration is a high-risk activity, often times resulting in no commercially productive reservoirs being discovered. Moreover, costs associated with operating within our industry are substantial.

The oil and gas industry is highly competitive. We compete with major and diversified energy companies, independent oil and gas businesses and individual operators. In addition, the industry as a whole competes with other businesses that supply energy to industrial and commercial end users.

Extensive federal, state and local regulation of the industry significantly affects our operations. In particular, our activities are subject to stringent operational and environmental regulations. These regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning oil and gas wells and related facilities. These regulations may become more demanding in the future.

Approach to the Business

Profitable growth of our business will largely depend upon our ability to successfully find and develop new proved reserves of oil and natural gas in a cost effective manner. In order to achieve an overall acceptable rate of growth, we maintain a blended portfolio of low, moderate and higher risk exploration and development projects. We also attempt to make selected acquisitions of oil and gas properties to augment our growth and provide future drilling opportunities. We believe that this approach should allow for consistent increases in our oil and gas reserves, while minimizing the chance of failure. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. We periodically hedge our exposure to volatile oil and gas prices on a portion of our production to reduce price risk. As of June 30, 2004, we have entered into hedge contracts covering approximately 60% and 65% of our remaining expected 2004 natural gas and crude oil production, respectively. During the second and third quarter, we entered into new hedge contracts resulting in approximately 20% of our expected 2005 natural gas and crude oil production being hedged.

Implementation of our business approach relies on our ability to fund ongoing exploration and development projects with cash flow provided by operating activities and external sources of capital. In late 2003, we announced plans for record capital expenditures of approximately $28 million for 2004. Subsequently, we announced plans to expand the 2004 capital budget to approximately $39 million and now expect it to increase to approximately $40 to $45 million. We do not include acquisitions in our budgeted capital expenditures. Based on current expectations for production volumes and commodity prices, we expect to fund those capital expenditures from internally generated cash from operating activities.

Debt was reduced by $3.0 million in the first six months of 2004 to $18.0 million at June 30, 2004. As of that date, our debt to total capital ratio was approximately 16%, which we believe leaves us with the financial flexibility to continue to execute our business strategies.

Merger

On December 4, 2003 we completed our acquisition of Miller. Miller was an independent oil and gas exploration and production company with exploration efforts concentrated primarily in the Mississippi Salt Basin of

central Mississippi. We acquired Miller for the development and exploitation projects in each of Miller’s core areas, increased financial flexibility, and expansion of our core areas.

Under the terms of the merger agreement, each share of issued and outstanding common stock of Miller was converted into 1.22342 shares of Edge common stock. We issued approximately 2.6 million shares of Edge common stock to the shareholders of Miller in exchange for all of the outstanding common stock of Miller. The merger was treated as a tax-free reorganization and accounted for as a purchase business combination under generally accepted accounting principles.

The fair value of assets acquired from Miller totaled $15.7 million and included $6.4 million of cash. We incurred $1.2 million in costs associated with the merger resulting in cash acquired in the merger of $5.2 million for the year ended December 31, 2003. During the six months ended June 30, 2004 we incurred approximately $252,000 of expenses associated with the transaction.

The acquired Miller properties were estimated to contain at least 5.6 Bcfe of proved reserves at December 31, 2003, of which approximately 60% was natural gas and 100% was classified as proved developed. The acreage position was approximately 83,800 gross (17,200 net) acres with an option to acquire 80,000 gross (68,000 net) acres at December 31, 2003.We operate the majority of the acquired properties. Production from Miller properties for the six months ended June 30, 2004 was approximately 964,000 Mcfe.

Outlook

We expect our drilling program to increase from 36 wells (17.922 net) in 2003 to approximately 45 to 50 wells (23.4 to 26.0 net) in 2004. Our expected capital program will be approximately $40 to $45 million, approximately 60% greater than 2003, excluding acquisitions. Our expected production volumes combined with a strong commodity-pricing environment expected for the remainder of the year is anticipated to produce record cash flow. In order to manage the anticipated growth over the coming year, we are planning to increase our headcount resulting in increased G&A costs. To help protect against the possibility that commodity prices do not remain at the current levels, we have entered into several hedges covering approximately 60% of our expected natural gas production and 65% of our expected crude oil production streams for the remainder of 2004 to offset the negative impact of potential downward price movements. During the second quarter, we entered into new hedge contracts resulting in approximately 20% of our expected 2005 natural gas and crude oil production being hedged. We also expect to spend considerable effort in 2004 on acquisitions, as we seek to further our growth.

Our outlook and the expected results described above are both subject to change based upon factors that include but are not limited to drilling results, commodity prices, access to capital, the acquisitions market and factors referred to in “Forward Looking Statements.”

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Revenue Recognition

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

Oil and Natural Gas Properties

The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the successful-efforts method and the full-cost method. There are several significant differences between these methods. Under the successful-efforts method, costs such as geological and geophysical (“G&G”), exploratory dry holes and delay rentals are expensed as incurred whereas under the full-cost method these types of charges would be capitalized to their respective full-cost pool. In the measurement of impairment of oil and gas properties, the successful-efforts method of accounting follows the guidance provided in Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” where the first measurement for impairment is to compare the net book value of the related asset to its undiscounted future cash flows using commodity prices consistent with management expectations. Under the full-cost method, impairment is determined by comparing the net book value (full-cost pool) to the future net cash flows discounted at 10 percent using commodity prices in effect at the end of the reporting period. Guidance to determine this impairment is provided in SEC Regulation S-X Rule 4-10.

We have elected to use the full-cost method to account for our oil and gas activities. Under this method, all costs associated with acquisition, exploration and development of oil and gas reserves, 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, which constitutes one cost center. Although some of these costs may ultimately result in no additional reserves, we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. As a result, we believe that the full-cost method of accounting better reflects the true economics of exploring for and developing oil and gas reserves. Our financial position and results of operations would have been significantly different had we used the successful-efforts method of accounting for our oil and gas investments.

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. Unproved 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 and dismantlement costs and restoration and abandonment costs, net of estimated salvage value.

The capitalized costs of oil and natural gas properties are subject to a “ceiling test,” whereby to the extent that such capitalized costs subject to amortization in the full-cost pool (net of depletion, depreciation and amortization, asset retirement obligations 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 using hedge adjusted period end prices, such excess costs are charged to operations. Once incurred, an impairment of oil and natural gas properties is not reversible at a later date. Impairment of oil and natural gas properties is assessed on a quarterly basis in conjunction with our quarterly filings with the SEC. In accordance with Staff Accounting Bulletin (“SAB”) No.103, “Update of Codification of Staff Accounting Bulletins,” derivative instruments qualifying as cash flow hedges are included in the computation of limitation on capitalized costs. The period end price exceeded the cap established by one of the Company’s hedges at June 30, 2004 and thus a $284,000 reduction to the limitation threshold was used in this calculation. No adjustment related to the ceiling test was required during the six months ended June 30, 2004 or 2003.

Asset Retirement Obligations

We have certain obligations to remove tangible equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells. Under the full-cost method of accounting, as described in the preceding critical accounting policy sections, the estimated discounted costs of the abandonment obligations, net of salvage value, are currently included as a component of our depletion base and expensed over the production life of the oil and gas properties. Estimating the future asset removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

In 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” We adopted this statement effective January 1, 2003, as discussed in Note 1 to our Consolidated Financial Statements. SFAS No. 143 significantly changed the method of accruing for costs an entity is legally obligated to incur related to the retirement of fixed assets (“asset retirement obligations” or “ARO”). Primarily, the new statement requires us to record a separate liability for the discounted present value of our asset retirement obligations, with an offsetting increase to the related oil and gas properties on the balance sheet.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. In addition, increases in the discounted ARO liability resulting from the passage of time will be reflected as accretion expense in the consolidated statement of operations.

The adoption of SFAS No. 143 required a cumulative adjustment to reflect the impact of implementing the statement had the rule been in effect since inception. We, therefore, calculated the cumulative accretion expense on the ARO liability and the cumulative depletion expense on the corresponding property balance. The sum of these cumulative expenses was compared to the depletion expense originally recorded. Because the historically recorded depletion expense was lower than the cumulative expense calculated under SFAS No. 143, the difference resulted in a loss, which we recorded as cumulative effect of change in accounting principle on January 1, 2003.

Going forward, our depletion expense will be reduced since we will deplete a discounted amount of asset retirement costs rather than the undiscounted value previously depleted. The lower depletion expense under SFAS No. 143 is offset, however, by accretion expense, which reflects the increases in the discounted asset retirement obligation liability over time.

Oil and Natural Gas Reserves

Our estimate of proved reserves is based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves.

Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our depreciation, depletion, and amortization expense (“DD&A”) and accretion expense. Our oil and gas properties are also subject to a “ceiling” limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.

We engage an independent petroleum engineering firm to prepare an independent estimate of our proved hydrocarbon liquid and gas reserves.

Income Taxes

We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices). The Company is not currently required to pay any federal income taxes because of net operating loss carryforwards.

Derivatives and Hedging Activities

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.

Due to the instability of oil and natural gas prices, we may enter into, from time to time, price risk management transactions (e.g., swaps, collars and floors) for a portion of our oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from commodity 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. None of these instruments are used for trading purposes. Our management 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. Our Board of Directors reviews all hedging policies and trades. In accordance with SFAS No. 133, all derivatives are recorded on the balance sheet at fair value. We account for natural gas contracts as hedges of future cash flows from sale of natural gas. Accordingly, the effective portion of the changes in the fair value of the natural gas contracts are recorded initially in other comprehensive income. When the hedged production is sold, the realized gains and losses on the natural gas contracts are removed from other comprehensive income and recorded in oil and natural gas revenue. Ineffective portions of the changes in fair value of the natural gas contracts are recognized in oil and natural gas revenue as they occur. While the hedge contract is outstanding, the ineffective gain or loss may increase or decrease until settlement of the contract. There was no ineffectiveness recognized during the six months ended June 30, 2004 or 2003. For transactions not accounted for using hedge accounting, the change in the fair value is reflected in oil and natural gas revenue immediately.

There are certain complexities inherent in hedge accounting like variations in production from day to day, the possibility that the derivatives may be based on prices at different delivery points that the pricing of the Company’s production, and that prices at different delivery points can diverge. We 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 the hedged transactions. 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 is discontinued prospectively.

Stock-Based Compensation

We account for stock compensation plans under the intrinsic value method of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” No compensation expense is recognized for stock options that had an exercise price equal to or greater than the market value of their underlying common stock on the date of grant. As allowed by SFAS No. 123, “Accounting for Stock Based Compensation,” we have continued to apply APB Opinion No. 25 for purposes of determining net income. In December 2002, the 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. We elected not to change to the fair value method. Additionally, the statement amended 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, among other things, a non-cash charge to deferred compensation expense if the market price of our common stock on the last trading day of a reporting period is greater than the exercise price of certain stock 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. 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. We are required to report under this rule as a result of non-qualified stock options granted to employees and directors in prior years and re-priced in May of 1999, as well as certain newly issued options in conjunction with the repricing.

RESULTS OF OPERATIONS

This section includes discussion of our results of operations for the three-month and six-month periods ended June 30, 2004. We are an independent energy company engaged in the exploration, development, acquisition and production of oil and natural gas. Our resources and assets are managed and our results reported as one operating segment. We conduct our operations primarily along the onshore United States, Gulf Coast, with our primary emphasis in South Texas, Louisiana, Southeast New Mexico, and Southern Mississippi.

Second Quarter 2004 Compared to the Second Quarter 2003

Revenue and Production

Oil and natural gas revenue increased 98% from $8.0 million in the second quarter of 2003 to $15.8 million in the comparable 2004 period. For the three months ended June 30, 2004, natural gas production comprised 79% of total production and contributed 83% of total revenue, natural gas liquid (NGL) production comprised 12% of total production and contributed 6% of total revenue, and oil and condensate production comprised 9% of total production and contributed 11% of total revenue. For the second quarter of 2003, natural gas production comprised 76% of total production and contributed 81% of total revenue, NGL production comprised 15% of total production and contributed 8% of total revenue, and oil and condensate production comprised 9% of total production and contributed 11% of total revenue.

The following table summarizes volume and price information with respect to our oil and gas production for the three-month periods ended June 30, 2004 and 2003:

					2004 Period Compared to 2003 Period
							%
	Three Months Ended June 30,				Increase		Increase
	2004		2003		(Decrease)		(Decrease)
Production Volumes:
Natural gas (Mcf)	2,298,064		1,340,070		957,994		71	%
Natural gas liquids (Bbls)	57,602		43,123		14,479		34	%
Oil and condensate (Bbls)	45,832		25,852		19,980		77	%
Natural gas equivalent (Mcfe)	2,918,668		1,753,920		1,164,748		66	%
Average Sales Price:
Natural gas ($ per Mcf)(1)	$	5.75	$	4.86	$	0.89	18	%
Natural gas liquids ($ per Bbl)	$	14.87	$	14.28	$	0.59	4	%
Oil and condensate ($ per Bbl)(1)	$	38.97	$	33.70	$	5.27	16	%
Natural gas equivalent ($ per Mcfe) (1)	$	5.43	$	4.56	$	0.87	19	%
Operating Revenue:
Natural gas (1)	$	13,204,760	$	6,507,095	$	6,697,665	103	%
Natural gas liquids	856,777		615,981		240,796		39	%
Oil and condensate (1)	1,785,867		871,319		914,548		105	%
Total (1)	$	15,847,404	$	7,994,395	$	7,853,009	98	%

(1) Includes the effect of hedging and derivative transactions.

Our revenue is sensitive to changes in prices received for our products. A substantial portion of our production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. Imbalances in the supply and demand for oil and natural gas can have a dramatic effect on the prices we receive for our production. Political instability and availability of alternative fuels could impact worldwide supply, while the economy, weather and other factors outside of our control could impact demand.

Natural gas revenue increased 103% from $6.5 million for the three months ended June 30, 2003 to $13.2 million for the same period in 2004 due to significantly higher production and lower realized hedge losses. Average natural gas production increased 71% from 14.7 MMcf/D in the three months ended June 30, 2003 to 25.3 MMcf/D in the comparable 2004 period due to production from new wells drilled and acquired, primarily our O’Connor Ranch East, Gato Creek, Encinitas and Miller properties, partially offset by natural declines at our Austin Field and O’Connor Ranch properties. This increase in production compared to the prior year period resulted in an increase in revenue of approximately $5.5 million (based on 2003 comparable period pre-hedge prices). For the three months ended June 30, 2004, we realized natural gas hedge losses of $222,000. In addition, we recognized $186,500 of the premium paid for a hedge entered into in 2003. These losses decreased the effective natural gas sales price by $0.18 per Mcf. Included within natural gas revenue for the three months ended June 30, 2003 was $1.1 million representing realized losses from hedging activity. These losses decreased the effective natural gas sales price by $0.84 per Mcf for the three months ended June 30, 2003. Excluding the effect of hedges, the average natural gas sales price for production in the second quarter of 2004 was $5.93 per Mcf compared to $5.70 per Mcf for the same period in 2003. This increase in average price received resulted in increased revenue of approximately $0.5 million (based on current year production).

Revenue from the sale of NGLs totaled $0.9 million for the three months ended June 30, 2004, an increase of 39% from the 2003 second quarter total of $0.6 million. Production volumes for NGLs increased 34%, from 474 Bbls/D for the three months ended June 30, 2003 to 633 Bbls/D for the three months ended June 30, 2004 due primarily to increased production from new wells drilled and acquired. The increase in NGL production increased revenue by $206,800 (based on 2003 comparable period average prices). Higher average realized prices for the three months ended June 30, 2004 resulted in an increase in revenue of $34,000 (based on current year production). The average realized price for NGLs for the three months ended June 30, 2004 was $14.87 per barrel compared to $14.28 per barrel for the same period in 2003.

Revenue from the sale of oil and condensate totaled $1.8 million for the three months ended June 30, 2004, an increase of 105% from the comparable prior year period total of $0.9 million due to increased production and higher realized prices. Production volumes for oil and condensate increased 77% to 504 Bbls/D for the three months ended June 30, 2004 compared to 284 Bbls/D for the same prior year period due primarily to production from the properties acquired from Miller, as well as new wells drilled. The increase in oil and condensate production resulted in an increase in revenue of approximately $0.7 million (based on 2003 comparable period average prices). The average realized price for oil and condensate for the three months ended June 30, 2004 was $38.97 per barrel (including $0.67 per barrel associated with net derivative gains discussed below) compared to $33.70 per barrel in the same period of 2003. Higher average prices for the second quarter of 2004 resulted in an increase in revenue of approximately $0.2 million (based on current year production). Included in oil revenue for the three months ended June 30, 2004 was $103,300 of realized losses on oil derivatives offset by $133,800, representing a mark to market gain on the fair value of an oil derivative. We elected not to apply hedge accounting to this transaction. See Note 7 to our Consolidated Financial Statements.

Costs and Operating Expenses

The table below presents a detail of our expenses for the three months ended June 30, 2004 and 2003:

					2004 Period Compared to 2003 Period
	Three Months Ended June 30,				Increase (Decrease)			% Increase (Decrease)
	2004		2003		Increase (Decrease)			% Increase (Decrease)

Lease operating expenses	$	1,220,092	$	550,998	$	669,094		121	%
Severance and ad valorem taxes	1,210,208		521,904		688,304			132	%
Depreciation, depletion, amortization and accretion:
Oil and gas property and equipment	5,023,148		2,728,625		2,294,523			84	%
Other assets	92,023		115,946		(23,923		)	-21	%
ARO accretion	26,216		14,765		11,451			78	%
General and administrative expenses:
Deferred compensation – repriced options	337,386		—		337,386				*
Deferred compensation – restricted stock	114,600		89,775		24,825			28	%
Other general and administrative expenses	1,731,453		1,430,756		300,697			21	%
	9,755,126		5,452,769		4,302,357			79	%
Other expense, net	142,130		162,021		(19,891		)	-12	%
Total	$	9,897,256	$	5,614,790	$	4,282,466		76	%

* Not meaningful

Lease operating expenses for the three months ended June 30, 2004 totaled $1.2 million compared to $0.6 million in the same period of 2003, an increase of 121%. The 2003 acquisition of properties in South Texas and the Miller merger contributed 21% of the increase in costs in the second quarter of 2004 compared to the prior year second quarter. Wells drilled since the second quarter of 2003 as well as salt water disposal costs at the Thibodeaux well further increased the costs for the second quarter of 2004 compared to the prior year. Operating expenses averaged $0.42 per Mcfe for the three months ended June 30, 2004, compared to $0.31 per Mcfe for the same prior year period.

Severance and ad valorem taxes for the three months ended June 30, 2004 increased from $0.5 million in the second quarter of 2003, to $1.2 million in same period of 2004. Severance tax expense for the second quarter of 2004 of $1.1 million was 156% higher than the comparable prior year period as a result of higher revenue. For the three months ended June 30, 2004, severance tax expense was approximately 6.7% of revenue subject to severance taxes compared to 4.7% of revenue subject to severance taxes for the comparable 2003 period. The increase in tax as a percent of revenue was due primarily to a shift in our revenue stream to properties with higher severance tax rates. Ad valorem costs increased 29% from $99,639 in the second quarter of 2003 to $128,609 in the second quarter of 2004. On an equivalent basis, severance and ad valorem taxes averaged $0.41 per Mcfe and $0.30 per Mcfe for the three months ended June 30, 2004 and 2003, respectively.

Depletion, depreciation, and amortization (“DD&A”) and accretion expense for the three months ended June 30, 2004 totaled $5.1 million compared to $2.9 million for the three months ended June 30, 2003. Depletion on our oil and natural gas properties totaled $5.0 million for the second quarter of 2004 compared to $2.7 million in the same period of 2003. Depletion expense on a unit of production basis for the three months ended June 30, 2004 was $1.72 per Mcfe, compared to $1.56 per Mcfe in the second quarter of 2003. The increase in depletion expense was due primarily to the higher production levels in the second quarter of 2004 as compared to the same period of 2003 that resulted in an increase in expense of $1.8 million. The increase in rate for the second quarter of 2004 compared to 2003 added $0.5 million in depletion expense. Depreciation of furniture and fixtures totaled $92,023, a decrease of 21% compared to the prior year second quarter total of $115,946. We adopted SFAS No. 143 effective January 1,

2003. As a result, we recorded accretion expense associated with our asset retirement obligation for the three months ended June 30, 2004 and 2003 of $26,216 and $14,765, respectively.

Total G&A for the three months ended June 30, 2004 was $2.2 million, an increase of 44% compared to the prior year second quarter total of $1.5 million. G&A costs include deferred compensation related to repriced options (FIN 44), deferred compensation related to restricted stock grants and other G&A costs. A FIN 44 charge, as discussed above in Critical Accounting Policies and Estimates, of $0.3 million was incurred for the three months ended June 30, 2004 compared to no charge in the comparable prior year period. Amortization related to restricted stock awards granted over the past three years totaled $114,600 and $89,775, respectively, for the three months ended June 30, 2004 and 2003. Other G&A for the three months ended June 30, 2004, which does not include the deferred compensation expenses discussed above, totaled $1.7 million, a 21% increase from the comparable 2003 period total of $1.4 million. The increase in other G&A was attributable to higher salary and benefits as well as higher professional fees. For the three months ended June 30, 2004 and 2003, overhead reimbursement fees reduced G&A costs by $83,600 and $27,500, respectively. Capitalized G&A costs further reduced other G&A by $532,100 and $319,000, respectively, for the three months ended June 30, 2004 and 2003. Other G&A on a unit of production basis for the three months ended June 30, 2004 was $0.59 per Mcfe compared to $0.82 per Mcfe for the comparable 2003 period.

Included in other income (expense) was interest expense of $105,405 for the three months ended June 30, 2004 compared to $165,046 in the same 2003 period. Interest expense, including facility fees, was $228,329 for the second quarter of 2004 on weighted average debt of $19.5 million compared to interest expense of $213,135 on weighted average debt of approximately $21.5 million for the second quarter of 2003. Capitalized interest for the three months ended June 30, 2004 totaled $122,924 compared to $48,089 in the same prior year period. We also reported amortization of deferred loan costs of $40,748 during the second quarter of 2004. We amended our credit facility after the Miller merger resulting in loan costs of $422,304 that will be amortized over a three-year period ending December 31, 2006.

An income tax provision was recorded for the three months ended June 30, 2004 and 2003 of $2.1 million and $0.8 million, respectively. As of December 31, 2003, approximately $50.1 million of net operating loss carryforwards had been accumulated or acquired that begin to expire in 2012. Currently, we do not anticipate making federal tax payments in 2004.

For the three months ended June 30, 2004, we had net income of $3.9 million, or $0.30 basic earnings per share and $0.28 diluted earnings per share, as compared to net income of $1.5 million, or $0.16 basic and diluted earnings per share in the comparable 2003 period. Basic weighted average shares outstanding increased from approximately 9.5 million for the three months ended June 30, 2003 to 12.9 million in the comparable 2004 period. The increase in shares outstanding was due primarily to the issuance of stock for the acquisition of Miller in December 2003 as well as the exercise of options, the exercise of warrants and the vesting and issuance of restricted stock during 2003 and the first half of 2004.

Six Months Ended June 30, 2004 Compared to the Six Months Ended June 30, 2003

Revenue and Production

Oil and natural gas revenue increased 113% from $14.8 million in the first half of 2003 to $31.7 million in the comparable 2004 period. For the six months ended June 30, 2004, natural gas production comprised 78% of total production and contributed 83% of total revenue, NGL production comprised 12% of total production and contributed 6% of total revenue, and oil and condensate production comprised 10% of total production and contributed 11% of total revenue. For the first half of 2003, natural gas production comprised 75% of total production and contributed 79% of total revenue, NGL production comprised 15% of total production and contributed 8% of total revenue, and oil and condensate production comprised 10% of total production and contributed 13% of total revenue.

The following table summarizes volume and price information with respect to our oil and gas production for the six-month periods ended June 30, 2004 and 2003:

					2004 Period Compared to 2003 Period
					Increase (Decrease)		% Increase (Decrease)
	Six Months Ended June 30,
	2004		2003
Production Volumes:
Natural gas (Mcf)	4,720,044		2,478,439		2,241,605		90	%
Natural gas liquids (Bbls)	127,086		82,321		44,765		54	%
Oil and condensate (Bbls)	99,660		54,826		44,834		82	%
Natural gas equivalent (Mcfe)	6,080,520		3,301,321		2,779,199		84	%
Average Sales Price:
Natural gas ($ per Mcf)(1)	$	5.54	$	4.75	$	0.79	17	%
Natural gas liquids ($ per Bbl)	$	14.96	$	14.58	$	0.38	3	%
Oil and condensate ($ per Bbl)(1)	$	36.07	$	33.72	$	2.35	7	%
Natural gas equivalent ($ per Mcfe) (1)	$	5.21	$	4.49	$	0.72	16	%
Operating Revenue:
Natural gas (1)	$	26,166,411	$	11,784,315	$	14,382,096	122	%
Natural gas liquids	1,901,181		1,200,339		700,842		58	%
Oil and condensate (1)	3,594,469		1,848,511		1,745,958		94	%
Total (1)	$	31,662,061	$	14,833,165	$	16,828,896	113	%

(1) Includes the effect of hedging and derivative transactions.

Natural gas revenue increased 122% from $11.8 million for the six months ended June 30, 2003 to $26.2 million for the same period in 2004 due to significantly higher production and lower realized hedge losses. Average natural gas production increased 90% from 13.7 MMcf/D in the six months ended June 30, 2003 to 25.9 MMcf/D in the comparable 2004 period due to production from new wells drilled and acquired, primarily our O’Connor Ranch East, Gato Creek, Encinitas and Miller properties, partially offset by natural declines at our Austin Field and O’Connor Ranch properties. This increase in production compared to the prior year period resulted in an increase in revenue of approximately $13.7 million (based on 2003 comparable period pre-hedge prices). For the six months ended June 30, 2004, we realized natural gas hedge losses of $222,000. In addition, we recognized $213,800 of the premium paid for a hedge entered into in 2003. These losses decreased the effective natural gas sales price by $0.09 per Mcf. Included within natural gas revenue for the six months ended June 30, 2003 was $3.3 million representing realized losses from hedging activity. These losses decreased the effective natural gas sales price by $1.35 per Mcf for the six months ended June 30, 2003. Excluding the effect of hedges, the average natural gas sales price for production in the first half of 2004 was $5.63 per Mcf compared to $6.10 per Mcf for the same period in 2003. This decrease in average price received resulted in decreased revenue of approximately $2.2 million (based on current year production).

Revenue from the sale of NGLs totaled over $1.9 million for the six months ended June 30, 2004, an increase of 58% from the 2003 first half total of $1.2 million. Production volumes for NGLs increased 54%, from 455 Bbls/D for the six months ended June 30, 2003 to 698 Bbls/D for the same period in 2004 due primarily to increased production from new wells drilled and acquired. The increase in NGL production increased revenue by $652,700 (based on 2003 comparable period average prices). Higher average realized prices for the six months ended June 30, 2004 resulted in an increase in revenue of $48,100 (based on current year production). The average realized price for NGLs for the six months ended June 30, 2004 was $14.96 per barrel compared to $14.58 per barrel for the same period in 2003.

Revenue from the sale of oil and condensate totaled $3.6 million for the six months ended June 30, 2004, an increase of 94% from the comparable prior year period total of $1.8 million due primarily to production from our Miller properties acquired in late 2003. Production volumes for oil and condensate increased 82% to 548 Bbls/D for the six months ended June 30, 2004 compared to 303 Bbls/D. The increase in oil and condensate production resulted in an increase in revenue of approximately $1.5 million (based on 2003 comparable period pre-hedge prices). Included in oil revenue for the six months ended June 30, 2004 was $179,261, representing a mark to market

gain on the fair value of an oil derivative. We elected not to apply hedge accounting to this transaction. See Note 7 to our Consolidated Financial Statements. This gain was partially offset by $103,276 in realized losses related to our oil collars. The net gain related to the oil collars in place increased the average price per barrel by $0.76. Excluding the effect of the oil collars, the average realized price for oil and condensate for the six months ended June 30, 2004 was $35.31 per barrel compared to $33.72 per barrel in the same period of 2003. This higher average price for the first half of 2004 resulted in an increase in revenue of approximately $158,400 (based on current year production).

Costs and Operating Expenses

The table below presents a detail of our expenses for the six months ended June 30, 2004 and 2003:

					2004 Period Compared to 2003 Period
								%
	Six Months Ended June 30,				Increase			Increase
	2004		2003		(Decrease)			(Decrease)

Lease operating expenses	$	2,425,166	$	1,145,802	$	1,279,364		112	%
Severance and other taxes	2,254,922		1,041,059		1,213,863			117	%
Depreciation, depletion, amortization and accretion:
Oil and gas property and equipment	10,152,301		5,231,626		4,920,675			94	%
Other assets	179,000		345,730		(166,730		)	-48	%
ARO accretion	52,501		29,853		22,648			76	%
General and administrative expenses:
Deferred compensation – repriced options	1,448,485		—		1,448,485				*
Deferred compensation – restricted stock	211,100		176,439		34,661			20	%
Other general and administrative expenses	3,632,280		2,687,018		945,262			35	%
	20,355,755		10,657,527		9,698,228			91	%
Other expense, net	282,036		336,287		(54,251		)	-16	%
Total	$	20,637,791	$	10,993,814	$	9,643,977		88	%

* Not meaningful

Lease operating expenses for the six months ended June 30, 2004 totaled $2.4 million compared to $1.1 million in the same period of 2003, an increase of 112%. Current year results were impacted by the drilling of 37 wells since the second quarter of 2003 as well as increased production of 84% over 2003, the Miller merger, and acquisitions of properties from third parties. Operating expenses averaged $0.40 per Mcfe for the six months ended June 30, 2004, compared to $0.35 per Mcfe in the comparable prior year period.

Severance and ad valorem taxes for the six months ended June 30, 2004 increased from $1.0 million in the first half of 2003, to $2.3 million in same period of 2004. Severance tax expense for the first half of 2004 of $2.0 million was 131% higher than the comparable prior year period as a result of higher revenue. For the six months ended June 30, 2004, severance tax expense was approximately 6.4% of revenue subject to severance taxes compared to 4.8% of revenue subject to severance taxes for the comparable 2003 period. The increase in tax as a percent of revenue was due primarily to a shift in our revenue stream to properties with higher severance tax rates. Ad valorem costs increased 42% from $171,639 in the first half of 2003 to $243,072 in the first half of 2004. On an equivalent basis, severance and ad valorem taxes averaged $0.37 per Mcfe and $0.32 per Mcfe for the six months ended June 30, 2004 and 2003, respectively.

Depletion, depreciation, and amortization (“DD&A”) and accretion expense for the six months ended June 30, 2004 totaled $10.4 million compared to $5.6 million for the same period in 2003. Depletion on our oil and

natural gas properties totaled $10.2 million for the first half of 2004 compared to $5.2 million in the same period of 2003. Depletion expense on a unit of production basis for the six months ended June 30, 2004 was $1.67 per Mcfe, compared to a 2003 rate of $1.58 per Mcfe for the same period. The increase in depletion expense was due primarily to the higher production levels in the first half of 2004 as compared to the same period of 2003. Depreciation of furniture and fixtures for the six months ended June 30, 2004 totaled $179,000, a decrease of 48% compared to the prior year total of $345,730. In the first quarter of 2003, we moved offices resulting in accelerated amortization of leasehold costs associated with our prior office building lease. We adopted SFAS No. 143 effective January 1, 2003. As a result, we recorded accretion expense associated with our asset retirement obligation for the six months ended June 30, 2004 and 2003 of $52,501 and $29,853, respectively.

Total G&A for the six months ended June 30, 2004 was $5.3 million, an increase of 85% compared to the comparable prior year total of $2.9 million. G&A costs include deferred compensation related to repriced options, deferred compensation related to restricted stock grants and other G&A costs. A FIN 44 charge, as discussed in Critical Accounting Policies and Estimates, of $1.4 million was incurred for the six months ended June 30, 2004 compared to no charge in the comparable prior year period. Amortization related to restricted stock awards granted over the past three years totaled $211,100 and $176,439, respectively, for the six months ended June 30, 2004 and 2003. Other G&A for the six months ended June 30, 2004, which does not include the deferred compensation expenses discussed above, totaled $3.6 million, a 35% increase from the comparable 2003 period total of $2.7 million. The increase in other G&A was attributable to higher salary and benefits as well as higher professional fees and higher investor relation costs. In addition, we incurred costs associated with the Miller acquisition of $252,000. For the six months ended June 30, 2004 and 2003, overhead reimbursement fees reduced G&A costs by $130,000 and $56,200, respectively. Capitalized G&A costs further reduced other G&A by $1.0 million and $0.6 million, respectively, for the six months ended June 30, 2004 and 2003. Other G&A on a unit of production basis for the six months ended June 30, 2004 was $0.60 per Mcfe compared to $0.81 per Mcfe for the comparable 2003 period.

Included in other income (expense) was interest expense of $219,683 for the six months ended June 30, 2004 compared to $341,435 in the same 2003 period. Interest expense, including facility fees, was $431,162 for the first half of 2004 on weighted average debt of $20.2 million compared to interest expense of $465,447 on weighted average debt of approximately $21.3 million for the first half of 2003. Capitalized interest for the six months ended June 30, 2004 totaled $211,479 compared to $124,012 in the same prior year period. At June 30, 2004, our unproved property balance was $5.5 million compared to $5.0 million at December 31, 2003 and $5.3 at June 30, 2003, resulting in the higher capitalized interest for the 2004 period. We also reported deferred loan costs of $70,384 during the first half of 2004. We amended our credit facility after the Miller merger resulting in loan costs of $422,304 that will be amortized over a three-year period ending December 31, 2006.

An income tax provision was recorded for the six months ended June 30, 2004 and 2003 of $3.9 million and $1.4 million, respectively. As of December 31, 2003, approximately $50.1 million of net operating loss carryforwards had been accumulated or acquired that begin to expire in 2012. Currently, we do not anticipate making federal tax payments in 2004.

Upon adoption of SFAS No. 143 on January 1, 2003, we recorded a cumulative effect of a change in accounting principal of $357,825 (net of income taxes of $192,675) to recognize transition amounts for asset retirement obligations, asset retirement costs and accumulated depletion.

For the six months ended June 30, 2004, we had net income of $7.1 million, or $0.56 basic earnings per share and $0.53 diluted earnings per share, as compared to net income of $2.1 million, or $0.22 basic and diluted earnings per share in the comparable 2003 period. Basic weighted average shares outstanding increased from approximately 9.5 million for the six months ended June 30, 2003 to 12.8 million in the comparable 2004 period. The increase in shares outstanding was due primarily to the issuance of stock for the acquisition of Miller in December 2003 as well as the exercise of options, the exercise of warrants and the vesting and issuance of restricted stock during 2003 and the first half of 2004.

Liquidity and Capital Resources

In March 1997, we completed our initial public offering which provided us with proceeds of approximately $40 million, net of expenses and on May 6, 1999, we completed a “Private Offering” of 1,400,000 shares of common stock at a price of $5.40 per share. We also issued warrants, which were purchased for $0.125 per warrant, to acquire an additional 420,000 shares of common stock at $5.35 per share and were exercisable through May 6, 2004. Total proceeds of the private offering, net of offering costs, were approximately $7.4 million of which $4.9 million was used to repay debt under our revolving credit facility in place at the time, with the remainder being utilized to satisfy working capital requirements and to fund a portion of our exploration program. Pursuant to the terms of the private placement, we filed a registration statement with the SEC registering the resale of the shares of Common Stock and the warrants sold in the private placement, as well as the resale of any shares of Common Stock issued pursuant to such warrants. During November and December of 2003, we issued 375,000 shares of Common Stock in connection with the exercise of the warrants that resulted in proceeds to us of approximately $2.0 million. As of December 31, 2003, 45,000 of those warrants were outstanding. On March 2, 2004, Mr. Elias, our Chairman and Chief Executive Officer, exercised the remaining warrants which resulted in our issuance to him of 45,000 shares of common stock and net proceeds to us of $240,750.

Our primary ongoing source of capital is the cash flow generated from our operating activities supplemented by borrowings under our credit facility. Both of these sources are directly impacted by the amount of our oil and gas reserves, production volumes and the commodity prices we receive. Reserves and production volumes are influenced, in part, by the amount of future capital expenditures. In turn, capital expenditures are influenced by many factors including drilling results, oil and gas prices, industry conditions, prices, availability of goods and services and the extent to which oil and gas properties are acquired.

Capital Resources

Our primary needs for cash are for exploration, development and acquisition of oil and gas properties, and the repayment of principal and interest on outstanding debt. We attempt to fund our exploration and development activities primarily through internally generated cash flows and budget capital expenditures based on projected cash flows. We routinely adjust capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, and cash flow. We typically have funded acquisitions from borrowings under our credit facility and cash flow from operations. We have historically utilized net cash provided by operating activities, debt and equity as capital resources to obtain necessary funding for all of our cash needs. Available borrowing capacity under our facility was $27.0 million at June 30, 2004.

We had cash and cash equivalents at June 30, 2004 of $3.7 million consisting primarily of short-term money market investments, as compared to $1.3 million at December 31, 2003. Working capital was $3.0 million as of June 30, 2004, as compared to $0.9 million at December 31, 2003.

Net Cash Provided By Operating Activities

Cash flows provided by operating activities were $23.2 million for the six months ended June 30, 2004 compared to $8.4 million for the six months ended June 30, 2003. The significant increase in cash flows provided by operating activities for the six months ended June 30, 2004 compared to 2003 was primarily due to higher oil and gas production revenue partially offset by higher operating expense. Although fluctuations in commodity prices have been the primary reason for our short-term changes in cash flow from operating activities, increased production volumes significantly impacted us in the past few quarters. In an effort to reduce the volatility realized on commodity prices, we enter into derivative instruments. The impact in the first six months of 2004 was not significant due to relatively stable market prices. Oil and gas production revenue increased with an 84% increase in production and a 16% increase in the average price received for our production.

Net cash generated from operating activities is a function of commodity prices, which are inherently volatile and unpredictable, production volumes, operating efficiency and capital spending. Our business, as with other extractive industries, is a depleting one in which each gas equivalent produced must be replaced or we, and a critical source of our future liquidity, will shrink. Our overall production decline is approximately 17% per year.

Less predictable than production declines from our proved reserves is the impact of constantly changing oil and natural gas prices on cash flows and, therefore capital budgets. We mitigate the price risk with our hedging.

For these reasons, we only forecast, for internal use by management, an annual cash flow. These annual forecasts are revised monthly and capital budgets are reviewed by management and adjusted as warranted by market conditions. Longer-term cash flow and capital spending projections are neither developed nor used by management to operate our business.

In the event such capital resources are not available to us, our drilling and other activities may be curtailed.

Net Cash Used In Investing Activities

We reinvest a substantial portion of our cash flows in our drilling, acquisition, land and geophysical activities. As a result, we used $19.4 million in investing activities during the first six months of 2004. Capital expenditures of $16.3 million were attributable to the drilling of 20 gross wells, 18 of which were successful and one was being tested at quarter end. Leasehold acquisitions, including seismic data and other geological and geophysical expenditures totaled $2.7 million and acquisition costs totaled $0.1 million for the six months ended June 31, 2004. The remaining capital expenditures were associated with computer hardware and office equipment. Proceeds from the sale of oil and gas properties totaled $40,000 during the first six months of 2004. During the six months ended June 30, 2003, we used $7.6 million in investing activities. Capital expenditures of $7.6 million for the six months ended June 30, 2003, were partially offset by $55,096 in proceeds from the sale of oil and gas properties.

We currently anticipate capital expenditures in 2004 to be approximately $40 to $45 million. Approximately $32.8 to $37.8 million is allocated to our expected drilling and production activities; $4.6 million is allocated to land and seismic activities; and $2.6 million relates to capitalized interest and G&A and other. We plan to fund these expenditures from expected cash flow from operations plus some modest incremental borrowings. We have not explicitly budgeted for acquisitions; however, we do expect to spend considerable effort evaluating acquisition opportunities. We expect to fund acquisitions through traditional reserve-based bank debt and/or the issuance of equity and, if required, through additional debt and equity financings. We currently have $27.0 million of unused borrowing capacity under our credit facility.

Net Cash Provided By Financing Activities

Cash flows used in financing activities totaled $1.5 million for the six months ended June 30, 2004. Repayments of $3.0 million under our current credit facility as well as deferred loan costs of $0.4 million associated with amending that facility after the Miller merger were partially offset by $1.9 million in proceeds from the issuance of common stock related to options and warrants exercised in the first half of 2004. Cash flows provided by financing activities totaled $0.5 million for the six months ended June 30, 2003, and included borrowings of $1.7 million and payments of $1.2 million under our credit facility as well as $53,499 in proceeds from the issuance of common 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 2004 capital expenditures, commitments and working capital requirements through cash flows from operations, and to the extent necessary other financing activities. The projected 2004 cash flows from operations are estimated to be sufficient to fund our budgeted exploration and development program. We believe we will be able to generate capital resources and liquidity sufficient to fund our capital expenditures and meet such financial obligations as they come due.

Credit Facility

In March 2004, but effective December 31, 2003, the Company entered into a new amended and restated credit facility (the “Credit Facility”) which permits borrowings up to the lesser of (i) the borrowing base or (ii) $100 million. Borrowings under the Credit Facility bear interest at a rate equal to prime plus 0.50% or LIBOR plus 2.25%. As of June 30, 2004, $18.0 million in borrowings were outstanding under the Credit Facility and our interest

rate is 3.61%. The Credit Facility matures December 31, 2006 and is secured by substantially all of the Company’s assets.

Effective June 2004, the borrowing base under the Credit Facility was increased to $45.0 million from $40.0 million as a result of the acquisition of properties in the Miller merger and our drilling activities since the last redetermination. Available borrowing capacity under our facility was $27.0 million at June 30, 2004. We expect to redetermine our existing borrowing base in October 2004, and semiannually thereafter.

• The EBITDAX to Interest Expense ratio requires that (a) our consolidated EBITDAX (defined as EBITDA plus similar non-cash items and exploration and abandonment expenses for such period) for the four fiscal quarters then ended to (b) our consolidated interest expense for the four fiscal quarters then ended, to not be less than 3.5 to 1.0.

• The Working Capital ratio requires that the amount of our consolidated current assets less our consolidated current liabilities, as defined in the agreement, be at least $1.0 million.

• The Maximum Leverage ratio requires that the ratio, as of the last day of any fiscal quarter, of (a) Total Indebtedness (as defined in the Credit Facility) as of such fiscal quarter to (b) an amount equal to consolidated EBITDAX for the two quarters then ended times two, not be greater than 3.0 to 1.0. Consolidated EBITDAX is a component of negotiated covenants with our lenders and is presented here as part of the Company’s disclosure of its covenant obligations.

Shelf Registration Statement

We filed a $150 million shelf registration statement with the SEC, which became effective in May 2004. Under the shelf registration statement, we may issue, from time to time, any combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities in one or more offerings to those persons who agree to purchase our securities. At June 30, 2004, we had $150 million remaining for issuance under the shelf registration. We have no immediate plans to issue equity securities, however we will continue to explore opportunities in the future to replace existing debt and otherwise access capital through issuances of debt securities under this registration statement. Our ability to utilize the shelf registration statement will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.

Off Balance Sheet Arrangements

We currently do not have any off balance sheet arrangements.

Contractual Cash Obligations

There were no material changes, outside the ordinary course of our business, in lease obligations or other contractual obligations since December 31, 2003.

Recently Issued Accounting Pronouncements

In March 2004, the FASB issued an exposure draft entitled “Share-Based Payment, an Amendment of FASB Statement No. 123 and 95.” This proposed statement addresses the accounting for share-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may be settled by the issuance of such equity instruments. The proposed statement would eliminate the ability to account for share-based compensation transactions using APB Opinion No. 25, “Accounting for Stock Issued to Employees”, and generally would require instead that such transactions be accounted for using a fair-value-based method. As

proposed, this statement would be effective for the Company on January 1, 2005. We currently expect the impact on results of operations to be similar to the pro forma disclosures made in Note 1 to the consolidated financial statements.

Hedging Activities

Gas Hedges

In August 2003, we purchased natural gas options that cover 10,000 MMbtu 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 June 30, 2004 the market value of this instrument was a liability of approximately $452,400.

In December 2003, we entered into a costless natural gas collar covering 5,000 MMbtu per day for the period January 1, 2004 to March 31, 2004 with a floor of $4.50 per MMbtu and a ceiling of $7.05 per MMbtu. The natural gas collar expired at no cost to us.

In February 2004, we entered into a costless natural gas collar covering 5,000 MMbtu per day for the period April 1, 2004 to September 30, 2004 with a floor of $4.50 per MMbtu and a ceiling of $6.20 per MMbtu. At June 30, 2004 the market value of this instrument was a liability of approximately $70,400.

In March 2004, we entered into a costless natural gas collar covering 5,000 MMbtu per day for the period October 1, 2004 to December 31, 2004 with a floor of $4.50 per MMbtu and a ceiling of $7.25 per MMbtu. At June 30, 2004 the market value of this instrument was an asset of approximately $116,800.

In May 2004, we entered into a costless natural gas collar covering 10,000 MMbtu per day for the period January 1, 2005 to March 31, 2005 with a floor of $5.00 per MMbtu and a ceiling of $10.39 per MMbtu. At June 30, 2004 the market value of this instrument was a liability of approximately $8,300 and is netted against current assets.

Oil Derivatives

In March 2004, we entered into a costless crude oil collar covering 400 barrels per day for the period April 1, 2004 to December 31, 2004 with a floor of $30.00 per barrel and a ceiling of $35.50 per barrel. At June 30, 2004 the market value of this instrument was a gain of approximately $217,400 and is reflected in current assets.

In May 2004, we entered into a costless crude oil collar covering 200 barrels per day for the period January 1, 2005 to December 31, 2005 with a floor of $30.00 per barrel and a ceiling of $39.15 per barrel. At June 30, 2004 the market value of this instrument was a loss of approximately $38,100 and is reflected in current liabilities.

Hedge accounting was not applicable to either of the oil collar transactions so the associated gain or loss will not be deferred in Other Comprehensive Income, rather reported as an unrealized gain or loss in oil and natural gas revenue.

Tax Matters

At December 31, 2003, we had cumulative net operating loss carryforwards (“NOLs”) for federal income tax purposes of approximately $50.1 million, including $17.4 million of NOLs acquired in the Miller acquisition, that will begin to expire in 2012. We currently anticipate that all of these NOLs will be utilized in connection with federal income taxes payable in the future. Our ability to fully utilize the NOLs assumes that certain items, primarily intangible drilling costs, have been written off for tax purposes in the current year. However, we have not made a final determination if an election will be made to capitalize all or part of these items for tax purposes in the future.

ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk from changes in interest rates and commodity prices. We use a credit facility, which has a floating interest rate, to finance a portion of our operations. We are not subject to fair value risk resulting from changes in our floating interest rates. The use of floating rate debt instruments provides a benefit due to downward interest rate movements but does not limit us to exposure from future increases in interest rates. Based on the June 30, 2004 outstanding borrowings and a floating interest rate of 3.61%, a 10% change in interest rates would result in an increase or decrease of interest expense of approximately $62,000 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 2003, due to the instability of prices and to achieve a more predictable cash flow, we put in place two natural gas collars for a portion of our 2004 production. During the first half of 2004, we put in place three additional natural gas collars and two crude oil collars covering 2004 and 2005 production and in July 2004 we put in place two additional natural gas collars for 2005 production. Please refer to Note 7 to our consolidated financial statements. While the use of these arrangements may limit the benefit to us of increases in the price of oil and natural gas, it also limits the downside risk of adverse price movements. At June 30, 2004, the fair value of the outstanding hedges was a liability of approximately $235,000. A 10% change in the commodity price per unit, 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 $86,200.

ITEM 4. CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2004 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 SEC’s rules and forms.

There has been no change in our internal controls over financial reporting that occurred during the three months ended June 30, 2004 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

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.

The Company intends to vigorously contest the proposed adjustments and has not recognized any provision for the additional franchise tax that would result from the proposed deficiency.

Item 2 - Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities		None
Item 3 - Defaults Upon Senior Securities		None
Item 4 - Submission of Matters to a Vote of Security Holders

Our stockholders voted on the following matters at the Annual Meeting of Shareholders on May 5, 2004:

	For	Against	Withheld	Abstain	Broker Non Votes
(A) Election of Directors:
Stanley S. Raphael	11,261,698	—	432,565	—	—
Robert W. Shower	11,312,616	—	381,647	—	—
David F. Work	11,315,050	—	379,213	—	—

(B) Approval of the Appointment of KPMG LLP as Independent Auditors	11,585,046	42,282	—	66,935	—

In addition to the election of the directors indicated above, the following directors continued as directors following the meeting: Thurmon Andress, Vincent S. Andrews, John W. Elias, Joseph R. Musolino, and John Sfondrini.

Item 5 - Other Information

None

Item 6 - Exhibits and Reports on Form 8-K

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

INDEX TO EXHIBITS

Exhibit No.

2.1	—	Amended and Restated Combination Agreement by and among (i) Edge Group II Limited Partnership, (ii) Gulfedge Limited Partnership, (iii) Edge Group Partnership, (iv) Edge Petroleum Corporation, (v) Edge Mergeco, Inc. and (vi) the Company, dated as of January 13, 1997 (Incorporated by reference from exhibit 2.1 to the Company’s Registration Statement on Form S-4 (Registration No. 333-17269)).

2.2	—	Agreement and Plan of Merger dated as of May 28, 2003 among Edge Petroleum Corporation, Edge Delaware Sub Inc. and Miller Exploration Company (Miller”) (Incorporated by reference from Annex A to the Joint Proxy Statement/Prospectus contained in the Company’s Registration Statement on Form S-4/A filed on October 31, 2003 (Registration No. 333-106484)).

3.1	—	Restated Certificate of Incorporation of the Company (Incorporated by reference from exhibit 3.1 to the Company’s Registration Statement on Form S-1/A filed on February 5, 1997 (Registration No. 333-17267)).

3.2	—	Certificate of Amendment to the Restated Certificate of Incorporation of the Company (Incorporated by reference from exhibit 3.1 to the Company’s Registration Statement on Form S-1/A filed on February 5, 1997 (Registration No. 333-17267)).

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

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

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

4.1	—	Third Amended and Restated Credit Agreement dated December 31, 2003 by and between Edge Petroleum Corporation, Edge Petroleum Exploration Company, Edge Petroleum Operating Company, Inc., Miller Oil Corporation, and Miller Exploration Company, as borrowers, and Union Bank of California, N.A., a national banking association, as Agent for itself and as lender. (Incorporated by reference from exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).

*4.2	—	Letter Agreement dated as of June 8, 2004 by and between Edge Petroleum Corporation, Edge Petroleum Exploration Company, Edge Petroleum Operating Company, Inc., Miller Oil Corporation, and Miller Exploration Company, as borrowers, and Union Bank of California, N.A., a national banking association, as Agent for itself and as lender.

4.3	—	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).

4.4	—	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).

4.5	—	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).

4.6	—	Registration Rights Agreement by and among Edge, Guardian Energy Management Corp., Kelly E. Miller and the Debra A. Miller Trust, dated December 4, 2003 (Incorporated by reference from exhibit 4.2 of the Company’s Registration Statement on Form S-3 filed on February 3, 2004 (Registration No. 333-112462)).

4.7	—	Securities Purchase Agreement between Miller and Guardian Energy Management Corp., dated July 11, 2000 (Incorporated by reference from exhibit 10.1 to Miller’s Current Report on Form 8-K, filed on July 25, 2000).

4.8	—	Warrant between Miller and Guardian Energy Management Corp., dated July 11, 2000, exercisable for 900,000 shares of Miller’s common stock (as adjusted for the one for ten reverse stock split of Miller effected October 11, 2002 and as adjusted pursuant to the Agreement and Plan of Merger by and among the Company, Edge Delaware Sub Inc. and Miller) (incorporated by reference from Exhibit 4.3 to Miller’s Current Report on Form 8-K filed on July 25, 2000).

4.9	—	Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference from exhibit 10.1(a) to Miller’s Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 000-23431)).

4.10	—	Amendment No. 1 to the Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference to Exhibit 4.2 from Miller’s Registration Statement on Form S-8 filed on April 11, 2001 (Registration No. 333-58678)).

4.11	—	Amendment No. 2 to the Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference from Exhibit 4.3 to Miller’s Registration Statement on Form S-8 filed on April 11, 2001 (Registration No. 333-58678)).

4.12	—	Form of Miller Stock Option Agreement (Incorporated by reference from exhibit 10.1(b) to Miller’s Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 000-23431)).

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 10.2 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 10.4 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 June 1, 2004.

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	—	Form of Director’s Restricted Stock Award Agreement under the Incentive Plan of Edge Petroleum Corporation.

10.13	—	Severance Agreements by and between Edge Petroleum Corporation and the Officers of the Company named herein. (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).

10.14	—	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).

10.15	—	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)).

10.16	—	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 Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2	—	Certification by Michael G. Long, Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.1	—	Certification by John W. Elias, Chief Executive Officer, pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2	—	Certification by Michael G. Long, Chief Financial Officer, pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith.

(B) Reports on Form 8-K

The Company filed a Current Report on Form 8-K April 15, 2004 (information furnished not filed) announcing the issuance of a press release reporting its first quarter 2004 operating results and attaching a copy of the press release as an exhibit.

The Company filed a Current Report on Form 8-K on May 5, 2004 (information furnished not filed) announcing the issuance of a press release reporting first quarter financial results and updated 2004 guidance and attaching a copy of the press release as an exhibit.

The Company filed a Current Report on Form 8-K on May 5, 2004 (information furnished not filed) announcing the issuance of a press release reporting an increased capital spending plan for 2004 and attaching a copy of the press release as an exhibit.

The Company filed a Current Report on Form 8-K on May 21, 2004 (information furnished not filed) announcing the issuance of a press release announcing the filing of a Form S-3, shelf registration statement with the Securities and Exchange Commission and attaching a copy of the press release as an exhibit.

The Company filed a Current Report on Form 8-K on June 30, 2004 announcing a change in the registrant’s certifying accountant.

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	August 13, 2004	/s/ John W. Elias
		John W. Elias
		Chief Executive Officer and
		Chairman of the Board


Date	August 13, 2004	/s/ Michael G. Long
		Michael G. Long
		Senior Vice President and
		Chief Financial Officer

INDEX TO EXHIBITS

Exhibit No.

2.1	—	Amended and Restated Combination Agreement by and among (i) Edge Group II Limited Partnership, (ii) Gulfedge Limited Partnership, (iii) Edge Group Partnership, (iv) Edge Petroleum Corporation, (v) Edge Mergeco, Inc. and (vi) the Company, dated as of January 13, 1997 (Incorporated by reference from exhibit 2.1 to the Company’s Registration Statement on Form S-4 (Registration No. 333-17269)).

2.2	—	Agreement and Plan of Merger dated as of May 28, 2003 among Edge Petroleum Corporation, Edge Delaware Sub Inc. and Miller Exploration Company (Miller”) (Incorporated by reference from Annex A to the Joint Proxy Statement/Prospectus contained in the Company’s Registration Statement on Form S-4/A filed on October 31, 2003 (Registration No. 333-106484)).

3.1	—	Restated Certificate of Incorporation of the Company (Incorporated by reference from exhibit 3.1 to the Company’s Registration Statement on Form S-1/A filed on February 5, 1997 (Registration No. 333-17267)).

3.2	—	Certificate of Amendment to the Restated Certificate of Incorporation of the Company (Incorporated by reference from exhibit 3.1 to the Company’s Registration Statement on Form S-1/A filed on February 5, 1997 (Registration No. 333-17267)).

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

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

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

4.1	—	Third Amended and Restated Credit Agreement dated December 31, 2003 by and between Edge Petroleum Corporation, Edge Petroleum Exploration Company, Edge Petroleum Operating Company, Inc., Miller Oil Corporation, and Miller Exploration Company, as borrowers, and Union Bank of California, N.A., a national banking association, as Agent for itself and as lender. (Incorporated by reference from exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).

*4.2	—	Letter Agreement dated as of June 8, 2004 by and between Edge Petroleum Corporation, Edge Petroleum Exploration Company, Edge Petroleum Operating Company, Inc., Miller Oil Corporation, and Miller Exploration Company, as borrowers, and Union Bank of California, N.A., a national banking association, as Agent for itself and as lender.

4.3	—	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).

4.4	—	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).

4.5	—	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).

4.6	—	Registration Rights Agreement by and among Edge, Guardian Energy Management Corp., Kelly E. Miller and the Debra A. Miller Trust, dated December 4, 2003 (Incorporated by reference from exhibit 4.2 of the Company’s Registration Statement on Form S-3 filed on February 3, 2004 (Registration No. 333-112462)).

4.7	—	Securities Purchase Agreement between Miller and Guardian Energy Management Corp., dated July 11, 2000 (Incorporated by reference from exhibit 10.1 to Miller’s Current Report on Form 8-K, filed on July 25, 2000).

4.8	—	Warrant between Miller and Guardian Energy Management Corp., dated July 11, 2000, exercisable for 900,000 shares of Miller’s common stock (as adjusted for the one for ten reverse stock split of Miller effected October 11, 2002 and as adjusted pursuant to the Agreement and Plan of Merger by and among the Company, Edge Delaware Sub Inc. and Miller) (incorporated by reference from Exhibit 4.3 to Miller’s Current Report on Form 8-K filed on July 25, 2000).

4.9	—	Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference from exhibit 10.1(a) to Miller’s Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 000-23431)).

4.10	—	Amendment No. 1 to the Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference to Exhibit 4.2 from Miller’s Registration Statement on Form S-8 filed on April 11, 2001 (Registration No. 333-58678)).

4.11	—	Amendment No. 2 to the Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference from Exhibit 4.3 to Miller’s Registration Statement on Form S-8 filed on April 11, 2001 (Registration No. 333-58678)).

4.12	—	Form of Miller Stock Option Agreement (Incorporated by reference from exhibit 10.1(b) to Miller’s Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 000-23431)).

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 10.2 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 10.4 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 June 1, 2004.

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	—	Form of Director’s Restricted Stock Award Agreement under the Incentive Plan of Edge Petroleum Corporation.

10.13	—	Severance Agreements by and between Edge Petroleum Corporation and the Officers of the Company named herein. (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).

10.14	—	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).

10.15	—	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)).

10.16	—	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 Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2	—	Certification by Michael G. Long, Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.1	—	Certification by John W. Elias, Chief Executive Officer, pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2	—	Certification by Michael G. Long, Chief Financial Officer, pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith.