EDGE PETROLEUM CORP - 10-Q Quarterly Report

EDGE PETROLEUM CORPORATION

	September 30, 2004				December 31, 2003
	(Unaudited)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$		2,492,606		$	1,327,081
Accounts receivable, trade, net of allowance of $525,248 at September 30, 2004 and December 31, 2003	12,670,527				8,889,734
Accounts receivable, joint interest owners, net of allowance of $82,000 at September 30, 2004 and December 31, 2003	2,163,203				1,797,877
Deferred tax asset	1,390,345				1,138,492
Derivative financial instruments	—				120,801
Other current assets	1,453,228				1,186,987
Total current assets	20,169,909				14,460,972
PROPERTY AND EQUIPMENT, Net — full-cost method of accounting for oil and natural gas properties (including unproved costs of $9.1 million and $5.0 million at September 30, 2004 and December 31, 2003, respectively)	124,407,453				97,980,757
DEFERRED TAX ASSET	789,612				5,570,137
OTHER ASSETS	319,032				—
TOTAL ASSETS	$		145,686,006		$	118,011,866

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable, trade	$	122,407			$	1,732,935
Accrued liabilities	23,761,443				11,456,036
Asset retirement obligation	411,092				323,513
Derivative financial instruments	2,159,880				—
Total current liabilities	26,454,822				13,512,484

ASSET RETIREMENT OBLIGATION	1,591,628				1,488,482

DERIVATIVE FINANCIAL INSTRUMENTS	117,083				—

LONG-TERM DEBT	22,000,000				21,000,000
Total liabilities	50,163,533				36,000,966
COMMITMENTS AND CONTINGENCIES (See Note 10)

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; 13,012,740 and 12,581,032 shares issued and outstanding at September 30, 2004 and December 31, 2003, respectively	130,127				125,810
Additional paid-in capital	79,639,744				75,282,007
Retained earnings	16,595,426				6,966,557
Accumulated other comprehensive loss	(842,824			)	(363,474		)
Total stockholders’ equity	95,522,473				82,010,900
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	145,686,006			$	118,011,866

See accompanying notes to consolidated financial statements

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004				2003
OIL AND NATURAL GAS REVENUE:
Oil and natural gas sales	$	15,181,874		$	9,719,008		$	47,203,800			$	27,888,053
Loss on hedging and derivatives	(1,939,409		)	(824,470		)	(2,299,274			)	(4,160,350			)
Total revenue	13,242,465			8,894,538			44,904,526				23,727,703
OPERATING EXPENSES:
Lease operating expenses	1,176,732			597,550			3,601,898				1,743,352
Severance and ad valorem taxes	891,194			561,787			3,146,116				1,602,846
Depletion, depreciation, amortization and accretion	5,446,446			3,727,034			15,830,248				9,334,243
General and administrative expenses:
Deferred compensation — repriced options	(153,808		)	—			1,294,677				—
Deferred compensation — restricted stock	143,500			93,604			354,600				270,043
Other general and administrative expenses	1,844,062			1,157,259			5,476,342				3,844,277
Total operating expenses	9,348,126			6,137,234			29,703,881				16,794,761
OPERATING INCOME	3,894,339			2,757,304			15,200,645				6,932,942

OTHER INCOME AND EXPENSE:
Interest income	8,087			8,292			16,118				13,440
Interest expense, net of amounts capitalized	(22,204		)	(128,651		)	(241,887			)	(470,086			)
Amortization of deferred loan costs	(35,948		)	—			(106,332			)	—
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE	3,844,274			2,636,945			14,868,544				6,476,296
INCOME TAX EXPENSE	(1,354,722		)	(946,109		)	(5,239,675			)	(2,313,302			)
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE	2,489,552			1,690,836			9,628,869				4,162,994
CUMULATIVE EFFECT OF ACCOUNTING CHANGE	—			—			—				(357,825			)
NET INCOME	2,489,552			1,690,836			9,628,869				3,805,169
OTHER COMPREHENSIVE INCOME (LOSS), net of taxes:
Unrealized hedge fair value gain (loss)	(578,834		)	1,000,658			(749,887			)	120,140
Reclassification to earnings of realized (gain) loss upon settlement of hedge contracts	312,332			171,792			270,537				637,958
Other comprehensive income (loss)	(266,502		)	1,172,450			(479,350			)	758,098
COMPREHENSIVE INCOME	$	2,223,050		$	2,863,286		$		9,149,519		$		4,563,267
BASIC EARNINGS PER SHARE:
Income before cumulative effect of accounting change	$	0.19		$	0.18		$		0.75		$		0.44
Cumulative effect of accounting change	—			—			—				(0.04			)
Net income per share	$	0.19		$	0.18		$		0.75		$		0.40
DILUTED EARNINGS PER SHARE:
Income before cumulative effect of accounting change	$	0.18		$	0.17		$		0.71		$		0.43
Cumulative effect of accounting change	—			—			—				(0.04			)
Net income per share	$	0.18		$	0.17		$		0.71		$		0.39
BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING	12,999,659			9,523,648			12,889,109				9,488,896
DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING	13,668,542			9,869,379			13,506,831				9,697,890

See accompanying notes to consolidated financial statements.

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

	Nine Months Ended September 30,
	2004				2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	9,628,869			$	3,805,169
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of accounting change	—				357,825
Loss on the fair value of derivatives	1,254,911				—
Deferred income taxes	5,239,675				2,313,302
Depletion, depreciation, amortization and accretion	15,830,248				9,334,243
Amortization of deferred loan costs	106,332				—
Deferred compensation	1,649,277				270,043
Changes in assets and liabilities:
Increase in accounts receivable, trade	(3,369,143			)	(2,915,624		)
Increase in accounts receivable, joint interest owners	(365,326			)	(96,698		)
Increase in other assets	(266,241			)	(343,368		)
Decrease in accounts payable, trade	(1,610,528			)	(312,119		)
Increase in accrued liabilities	12,388,677				3,879,236
Increase in accrued interest payable	—				5,448
Net cash provided by operating activities	40,486,751				16,297,457

CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property and equipment additions	(42,111,219			)	(25,531,943		)
Proceeds from the sale of oil and natural gas properties	45,000				330,096
Net cash used in investing activities	(42,066,219			)	(25,201,847		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from long-term debt	4,000,000				10,700,000
Payments of long-term debt	(3,000,000			)	(1,200,000		)
Net proceeds from issuance of common stock	2,170,357				84,603
Deferred loan costs	(425,364			)	—
Net cash provided by financing activities	2,744,993				9,584,603
NET INCREASE IN CASH AND CASH EQUIVALENTS	1,165,525				680,213

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	1,327,081				2,568,176
CASH AND CASH EQUIVALENTS, END OF PERIOD	$		2,492,606		$	3,248,389

See accompanying notes to consolidated financial statements.

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

								Accumulated
				Additional				Other			Total
	Common Stock			Paid-in		Retained		Comprehensive			Stockholders’
	Shares	Amount		Capital		Earnings		Loss			Equity
BALANCE, DECEMBER 31, 2003	12,581,032	$	125,810	$	75,282,007	$	6,966,557	$	(363,474	)	$	82,010,900
Issuance of common stock	431,708	4,317		2,249,310		—		—			2,253,627
Deferred compensation — restricted stock	—	—		354,600		—		—			354,600
Deferred compensation — repriced options	—	—		1,294,677		—		—			1,294,677
Change in valuation of hedging instruments	—	—		—		—		(479,350		)	(479,350		)
Tax benefit associated with exercise of non-qualified stock options	—	—		459,150		—		—			459,150
Net income	—	—		—		9,628,869		—			9,628,869
BALANCE, September 30, 2004	13,012,740	$	130,127	$	79,639,744	$	16,595,426	$	(842,824	)	$	95,522,473

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 and each of our quarterly reports on Form 10-Q for the corresponding prior 2004 quarterly periods.

Oil and Natural Gas Properties — Investments in oil and natural gas properties are accounted for using the full-cost method of accounting. 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. Among these differences is that, 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 are 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. The full-cost method follows guidance provided in SEC Regulation S-X Rule 4-10, where 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.

In accordance with 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. The Company also 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 activities.

Oil and natural gas properties are amortized based on a 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 $9.1 million and $5.0 million at September 30, 2004 and December 31, 2003, respectively, related to unproved property, which were excluded from capitalized costs being amortized. Unproved properties are evaluated quarterly, and as needed, 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. In accordance with SEC Staff Accounting Bulletin (“SAB”) No. 106, “Interaction of Statement 143 and the Full Cost Rules,” 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 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, such excess costs are charged to expense. Once incurred, an impairment of oil and natural gas properties is not reversible at a later date. In accordance with 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 was between the cap and floor established by the Company’s hedge contracts at September 30, 2004 and thus no impact was included in the calculation. Impairment of oil and natural gas properties is assessed on a quarterly basis in conjunction with the Company’s quarterly and annual filings with the SEC. No impairment related to the ceiling test was required during the nine-month periods ended September 30, 2004 or 2003.

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.

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, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets.” The Financial Accounting Standards Board (“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”) Nos. FAS 141-1 and FAS 142-1, “Interaction of FASB Statements No. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets, and EITF Issue No. 04-2, “Whether Mineral Rights Are Tangible or Intangible Assets.” In addition, FSP FAS 142-2, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil- and Gas-Producing Entities” 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.

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 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 September 30, 2004 and 2003 are as follows:

	Nine Months Ended September 30,
	2004			2003
ARO, Beginning of Period	$	1,811,995		$			942,736
Liabilities incurred in the current period	233,828			504,292
Liabilities settled in the current period	(123,231		)	(64,443				)
Accretion expense	80,128			44,652
Revisions	—			(9,714				)
ARO, End of Period	$	2,002,720		$		1,417,523
Current Portion	$	411,092		$		96,249
Long Term Portion	$	1,591,628		$	1,321,274

ARO liabilities incurred during the nine months ended September 30, 2004 include 28 new well obligations. Liabilities settled during the nine months ended September 30, 2004 included nine 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 September 30,						Nine Months Ended September 30,
	2004			2003			2004					2003
Net income as reported	$	2,489,552		$	1,690,836		$			9,628,869		$	3,805,169
Add:
Stock-based employee compensation expense included in reported net income, net of related income tax	(6,700		)	—			1,072,030					—
Deduct:
Total stock-based employee compensation expense determined under fair value based method for all awards, net of related income tax	(106,092		)	(53,769		)	(314,380				)	(168,030		)
Pro forma net income	$	2,376,760		$	1,637,067		$	10,386,519				$	3,637,139

Earnings Per Share:
Basic — as reported	$	0.19		$	0.18		$		0.75			$	0.40
Basic — pro forma	$	0.18		$	0.17		$		0.81			$	0.38

Diluted — as reported	$	0.18		$	0.17		$		0.71			$	0.39
Diluted — pro forma	$	0.17		$	0.17		$		0.77			$	0.38

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 $1.3

million was required for the nine months ended September 30, 2004. No charge related to FIN 44 was required during the nine-month period ended September 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 and generally would require instead that such transactions be accounted for using a fair-value-based method. The FASB continued deliberations throughout the third quarter and expects to issue a final statement in the fourth quarter of 2004. As proposed, this statement would be effective for the Company on January 1, 2005. We are currently evaluating the impact that may result from adoption of this proposed statement.

In September 2004, the SEC issued SAB No. 106 regarding the application of SFAS No. 143 by oil and gas producing entities that follow the full cost accounting method. SAB No. 106, effective in the fourth quarter of 2004, states that after adoption of SFAS No. 143, the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet should be excluded from the present value of estimated future net cash flows used for the full cost ceiling test calculation. It also confirms that the estimated dismantlement and abandonment costs, net of estimated salvage values, should be included in amortizable base used in computing unit-of-production depletion. This standard will also require companies to disclose in the accounting impact of SFAS No. 143 on their oil and gas producing activities, including the calculation of the ceiling test and depreciation, depletion and amortization. The Company currently does not expect the adoption of SAB No. 106 in the fourth quarter of 2004 to have any material impact on its financial statements, nor does it expect adoption to have a material effect on the results of the ceiling test calculation.

Reclassifications — Certain reclassifications of prior period statements have been made to conform to current reporting practices.

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%. At September 30, 2004, the interest rate applied to our outstanding balance was 4.06%. As of September 30, 2004, $22.0 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 September 30, 2004, the Company’s available borrowing capacity under this facility was $23.0 million.

Effective November 1, 2004, the Credit Facility’s borrowing base was increased from $45.0 million to $48.0 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 the ratio of (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.

• 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 lender and is presented here as part of the Company’s disclosure of its covenant obligations.

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 September 30, 2004, the Company had $150 million remaining for issuance under the shelf registration. 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 option 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 nine-month periods ended September 30, 2004 and 2003:

	Three Months Ended September 30, 2004						Three Months Ended September 30, 2003
	Income (Numerator)		Shares (Denominator)	Per Share Amount			Income (Numerator)		Shares (Denominator)	Per Share Amount
Basic EPS
Income available to common stockholders	$	2,489,552	12,999,659	$	0.19		$	1,690,836	9,523,648	$	0.18
Effect of dilutive securities:
Restricted stock	—		156,310	—			—		112,451	—
Common stock options			512,573	(0.01		)			183,756	(0.01		)
Warrants	—		—	—			—		49,524	—
Diluted EPS
Income available to common stockholders	$	2,489,552	13,668,542	$	0.18		$	1,690,836	9,869,379	$	0.17

	Nine Months Ended September 30, 2004							Nine Months Ended September 30, 2003
	Income (Numerator)		Shares (Denominator)	Per Share Amount				Income (Numerator)		Shares (Denominator)	Per Share Amount
Basic EPS
Income available to common stockholders	$	9,628,869	12,889,109	$	0.75			$	3,805,169	9,488,896	$	0.40
Effect of dilutive securities:
Restricted stock	—		139,223	(0.01			)	—		104,912	(0.01		)
Common stock options	—		478,499	(0.03			)	—		104,082	—
Diluted EPS
Income available to common stockholders	$	9,628,869	13,506,831	$		0.71		$	3,805,169	9,697,890	$	0.39

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 $5.2 million and $2.3 million was reported for the nine months ended September 30, 2004 and 2003, respectively. The Company was not required to pay income taxes in 2003 or 2002 because of the utilization of 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 nine months ended September 30, 2004 and 2003 is presented below:

Description	Number of Shares Issued	Fair Market Value
Nine months ended September 30, 2004:
Shares issued to satisfy restricted stock grants	61,136	$			384,708
Shares issued to fund the Company’s matching contribution under the Company’s 401-k plan	5,785	$		83,270
Nine months ended September 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	11,785	$	51,451

For the nine months ended September 30, 2004 and 2003, the non-cash portion of Asset Retirement Costs was $110,597 and $1,165,428, respectively. A supplemental disclosure of cash flow information for the nine months ended September 30, 2004 and 2003 is presented below:

	For the Nine Months Ended September 30,
	2004		2003
Cash paid during the period for:
Interest, net of amounts capitalized	$	241,887	$	336,939

Interest paid for the nine months ended September 30, 2004 and 2003 excludes amounts capitalized of $378,118 and $189,697, respectively. The Company was not required to pay income taxes in 2003 or 2002.

7. HEDGING AND DERIVATIVE ACTIVITIES

Due to the volatility of oil and natural gas prices, the Company periodically enters into price-risk management transactions (e.g., swaps, collars and floors) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits the Company’s ability to benefit from increases in the price of oil and natural gas, it also reduces the Company’s potential exposure to adverse price movements. The Company’s 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. None of these instruments are used for trading purposes. On a quarterly basis, the Company’s management sets all of the Company’s price-risk management policies, including volumes, types of instruments and counterparties. 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 continuously monitors the Company’s policies and trades.

All of these price-risk management transactions are considered derivative instruments and accounted for in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”. These derivative instruments are intended to hedge our price risk and may be considered hedges for economic purposes, but certain of these transactions may not qualify for cash flow hedge accounting. All derivative instrument contracts are recorded on the balance sheet at fair value. For those derivative instrument contracts that qualify for cash flow hedge accounting, the effective portion of the changes in the fair value of the contracts is recorded in other comprehensive income and the ineffective portion of the changes in the fair value of the contracts is recorded in revenue as they occur. While the contract is outstanding, the ineffective gain or loss may increase or decrease until settlement of the contract depending on the fair value at the measurement dates. When the hedged production is sold, the realized gains and losses on the contracts are removed from other comprehensive income and recorded in revenue. The Company is currently accounting for its natural gas contracts as cash flow hedges of future cash flows from the sale of natural gas. For those derivative instrument contracts that either do not qualify for cash flow 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 revenue immediately as unrealized gains or losses. The Company did not apply cash flow hedge accounting to its crude oil collars entered into in March and May/August of 2004, because although they were economic hedges, they did not qualify for hedge accounting.

For the nine months ended September 30, 2004 and 2003, the Company included in revenue realized and unrealized losses of $2.3 million and $4.2 million, respectively, related to its natural gas hedges and oil derivatives. There was no ineffectiveness recognized during the nine months ended September 30, 2004 or 2003.

	Nine Months Ended September 30,
	2004			2003
Natural gas hedging contract settlements	$	(222,000	)	$	(4,160,350	)
Oil derivative contract settlements	(410,713		)	—
Hedge premium reclassification	(411,650		)	—
Oil derivative contract unrealized change in fair value	(1,254,911		)	—
Loss on hedging and derivatives	$	(2,299,274	)	$	(4,160,350	)

A portion of the oil collar that extends into the fourth quarter of 2005 was classified as long term and the remaining contracts were classified as current based on the maturity of the contracts. The outstanding derivatives and hedges at September 30, 2004 and December 31, 2003 impacting the balance sheet were as follows:

							Unrealized Hedging Gains (Losses)
						Volumes	As of
Transaction	Transaction				Price	Per	September 30,				December 31,
Date	Type		Beginning	Ending	Per Unit	Day	2004				2003
*Natural Gas*:
12/03	Natural Gas Collar	(1)	01/01/04	03/31/04	$4.50-$7.05	5,000	$		—		$	37,688
08/03	Natural Gas Collar	(1)(2)	040/1/04	09/30/04	$4.50-$6.00	10,000	—				42,996
08/03	Natural Gas Collar	(1)(2)	01/01/04 10/01/04	03/31/04 12/31/04	$4.50-$7.00	10,000	(346,634			)	40,117
02/04	Natural Gas Collar	(1)	04/01/04	09/30/04	$4.50-$6.20	5,000	—				—
03/04	Natural Gas Collar	(1)	10/01/04	12/31/04	$4.50-$7.25	5,000	(138,163			)	—
05/04	Natural Gas Collar	(1)	01/01/05	03/31/05	$5.00-$10.39	10,000	(212,843			)	—
07/04	Natural Gas Collar	(1)	04/01/05	06/30/05	$5.00-$7.53	10,000	(166,387			)	—
07/04	Natural Gas Collar	(1)	07/01/05	09/30/05	$5.00-$7.67	10,000	(158,025			)	—

*Crude Oil:*
03/04	Crude Oil Collar	(3)	04/01/04	12/31/04	$30.00-$35.50	400	(620,428			)	—
05/04 (08/04)	Crude Oil Collar	(3)(4)	01/01/05	12/31/05	$35.00-$40.00	200/290	(634,483			)	—
							$	(2,276,963		)	$	120,801

(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 contract 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 nine months ended September 30, 2004.

(4) In August 2004, the Company replaced the contract that was outstanding at June 30, 2004 with a new contract that changes the volume and pricing terms. The put option is on 200 Bbl/D and the call option is on 290 Bbl/D. This transaction was completed at no additional cost to the Company.

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

			Effective Dates
Transaction Date	Hedge Type		Beginning	Ending	Price Per Unit	Volumes Per Day
10/04	Natural Gas Collar	(1)	1/1/05	12/31/05	$6.00-$9.52	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 nine months ended September 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.

	Nine Months Ended September 30, 2003
	(In thousands, except per share data)
STATEMENT OF OPERATIONS DATA
Oil and natural gas revenue	$	32,181
Income before cumulative effect of accounting change	$	6,906
Basic earnings per share before cumulative effect of accounting change	$	0.57
Diluted earnings per share before cumulative effect of accounting change	$	0.56

9. SUBSEQUENT EVENTS

On October 7, 2004 the Company executed an Asset Purchase Agreement to acquire oil and natural gas properties located in South Texas from Contango Oil & Gas Company for a cash purchase price of approximately $50 million. These properties are located primarily in Jim Hogg County, Texas. The Company expects approximately $5 million of the $50 million purchase price to be allocated to the unproved property category. The properties to be acquired consist of 38 non-operated producing wells with current net production of approximately 12 MMcfe per day as of October 2004, of which 90% is natural gas.

The purchase price is subject to adjustment for the results of operations after July 1, 2004 and title and environmental defects, if any. The acquisition is subject to certain closing conditions, including waivers or appropriate adjustments to the purchase price in the event of exercise of preferential purchase rights, obtaining certain consents from lessors and Contango’s shareholder approval. The transaction is expected to close on or before December 31, 2004. The Company plans to finance the planned acquisition through borrowings under the unused portion of its credit line, which is expected to increase as a result of this transaction, and the issuance of equity securities under its outstanding shelf registration statement.

10. 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 maintained 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. The State of Texas originally proposed that the franchise tax liability of the subsidiaries would be increased by approximately $3.0 million for the four-year period under audit.

During the third quarter the agent reduced the proposed franchise tax deficiency adjustment to the Company and its subsidiaries to $467,000. The Company intends to vigorously contest this proposed franchise tax assessment through appropriate administrative levels in the Comptroller’s Office. The next step in the administrative process is a hearing at the Comptroller’s Office scheduled for November 2004. Should the Company’s administrative appeals prove unsuccessful, the Company plans to seek further appellate relief through available judicial means. Due to its intention to continue to vigorously contest the proposed adjustments, the

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

The following is Management’s Discussion and Analysis (“MD&A”) 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. The following MD&A is intended to help the reader understand Edge Petroleum Corporation (“Edge”). 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 and each of our quarterly reports on Form 10-Q for the corresponding prior 2004 quarterly periods.

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 our merger with Miller Exploration Company (“Miller”), the consummation of the Contango Oil and Gas Company (“Contango”) acquisition, our financing plans related thereto, including any increase in our credit line, issuance of equity or debt, contribution of acquisition and any other benefit of such acquisition, our ability to access the capital markets to raise additional capital, our debt-to-total capital ratio, our drilling plans, our natural gas and oil production volumes, our 3-D project portfolio, our ability to hedge our risks, capital expenditures and capital program, future capabilities, the sufficiency of capital resources and liquidity to support working capital and capital expenditure requirements, sufficiency, growth and reinvestment of cash flows, our ability to control the timing of our future exploration and development requirements, use of NOLs, tax rates, the outcome of litigation and audits, the impact of changes in interest rates on our estimates of asset retirement obligations, the commodity pricing environment and the state of the economy 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, our ability and Contango’s ability to fulfill each of the closing conditions to the Contango property acquisition, risks relating to acquisitions 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. The Company undertakes no obligation to publicly update or revise any forward looking statements, whether as a result of new information, future events or otherwise.

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. In late 1998, we undertook a top-level management change 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. Our company generates revenues, income and cash flows by producing and marketing oil and natural gas produced from our oil and natural gas properties. We make significant capital expenditures in our exploration, development, and acquisition activities that allow us to continue generating

revenue, income and cash flows. In December 2003, we acquired 100 percent of the outstanding stock of Miller. The transaction was treated as a tax-free reorganization and accounted for as a purchase business combination. Miller continues to conduct exploration and development activities as a wholly-owned subsidiary of Edge.

This overview provides our perspective on the individual sections of MD&A, as well as helpful hints for reading these pages. Our MD&A includes the following sections:

• Industry and Economic Factors — a general description of value drivers of our business as well as opportunities, challenges and risks related to the oil and gas industry.

• Approach to the Business — additional information regarding our approach and strategy.

• Mergers & Acquisitions — information about significant changes in our business structure.

• Outlook — additional discussion relating to management’s outlook to the future of our business.

• Critical Accounting Policies and Estimates — a discussion of certain accounting policies that require critical judgments and estimates.

• Results of Operations — an analysis of our Company’s consolidated results for the periods presented in our financial statements.

• Liquidity — an analysis of cash flows and uses of cash.

• Capital Resources — an analysis of our sources of cash and contractual obligations.

• Risk Management Activities —supplementary information regarding our Company’s price-risk management activities involving commodity contracts that are accounted for at fair value.

• Tax Matters — supplementary discussion of income tax matters.

• Recently Issued Accounting Pronouncements — a discussion of certain accounting pronouncements recently issued that may impact our future results.

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. The economy as a whole has struggled thus far during 2004, but the oil and gas industry has experienced a high commodity price environment, which has positively impacted the entire industry as well as our Company.

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 the discovery of no commercially productive reservoirs. 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 September 30, 2004, we have entered into hedge contracts covering approximately 55% and 60% 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 40-50% and 35% of our expected 2005 natural gas and crude oil production, respectively, before any acquisitions, 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. In May 2004, we announced plans to expand the 2004 capital budget to approximately $39 million and in October 2004 our Board approved an increased 2004 capital budget of $52 million. We do not typically 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 plus some incremental borrowing on our line of credit.

Debt has increased by $1.0 million in the first nine months of 2004 to $22.0 million at September 30, 2004. As of that date, our debt to total capital ratio was approximately 19%, which we believe leaves us with the financial flexibility to continue to execute our business strategies.

Mergers and Acquisitions

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 Miller’s core area, 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 net cash acquired in the merger of $5.2 million for the year ended December 31, 2003. During the nine months ended September 30, 2004 we incurred approximately $233,000 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 nine months ended September 30, 2004 was approximately 1.5 Bcfe.

On October 7, 2004, we executed an Asset Purchase Agreement to acquire oil and natural gas properties located in South Texas from Contango for a cash purchase price of approximately $50 million. These properties, located primarily in Jim Hogg County, Texas and producing primarily from the Queen City formation, are in a geographic area that has been one of our most active and successful areas of focus in recent years. In addition to estimated proved reserves, our technical team has also identified a substantial number of additional drilling locations on undeveloped acreage with attractive exploitation and exploration potential. We expect approximately $5 million of the $50 million purchase price to be allocated to the unproved property category. The properties to be acquired consist of 38 non-operated producing wells with an average 68% working interest and 52% net revenue interest. As of October 2004, net production from the properties is approximately 12 MMcfe per day, and is 90% natural gas.

The purchase price is subject to adjustment for the results of operations after July 1, 2004 and title and environmental defects, if any. The acquisition is subject to certain closing conditions, including obtaining waivers or appropriate adjustments to the purchase price in the event of exercise of preferential purchase rights, obtaining certain consents from lessors and Contango’s shareholder approval. The transaction is expected to close on or before December 31, 2004. We plan to finance the planned acquisition through borrowings under the unused portion of our credit line, which is expected to increase as a result of this transaction, and the issuance of common stock. Following any such issuance of common stock, we intend to maintain our financial goal of a debt-to-total capital ratio of less than 30%.

Outlook

We expect our drilling program to increase from 36 wells (17.922 net) in 2003 to approximately 50 wells (28.0 net) in 2004. Our expected capital program, excluding acquisitions, will be approximately $52 million, approximately 85% greater than 2003. 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 realized and anticipated growth over the year, we have increased our headcount from 35 employees as of September 30, 2003 to 51 employees as of September 30, 2004 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 55% of our expected natural gas production and 60% 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 and third quarter, we entered into new hedge contracts resulting in approximately 40-50% of our expected 2005 natural gas and 35% of our expected 2005 crude oil production being hedged. We also expect to continue 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, contingent assets and liabilities and the related disclosures in the accompanying financial statements. Changes in these estimates and assumptions could materially affect our financial position, results of operations or cash flows. Management considers an accounting estimate to be critical if:

• it requires assumptions to be made that were uncertain at the time the estimate was made, and

• changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated results of operations or financial condition.

All other significant accounting policies that we employ are presented in the notes to the consolidated financial statements. The following discussion presents information about the nature of our most critical accounting estimates, our assumptions or approach used and the effects of hypothetical changes in the material assumptions used to develop each estimate.

Nature of Critical Estimate Item: Oil & 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 economics of producing the reserves may change and therefore the estimate of proved reserves also may change. 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.

Assumptions/Approach Used: Units-of-production method to amortize our oil and natural gas properties — The quantity of reserves could significantly impact our depletion expense. Any reduction in proved reserves without a corresponding reduction in capitalized costs will increase the depletion rate.

“Ceiling” Test — The full-cost method of accounting for oil and gas properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full-cost ceiling calculation. The ceiling is the discounted present value of our estimated total proved reserves adjusted for taxes and the impact of hedges on pricing, using a 10% discount rate. To the extent that our capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense. Once incurred, this impairment of oil and gas properties is not reversible at a later date even if oil and gas prices increase. No such impairment was required in the nine months ended September 30, 2004 and 2003. This calculation of our proved reserves could significantly impact our ceiling limitation used in determining whether an impairment of our capitalized costs is necessary. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are generally held constant indefinitely. Therefore, the future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs, but rather are based on prices and costs in effect as of the end of the period. Oil and natural gas prices used in the reserve valuation at September 30, 2004 were $29.78 per barrel and $6.80 per MMBtu.

Effect if different assumptions used: Units-of-production method to amortize our oil and natural gas properties — A 10% decrease in reserves would have increased our depletion expense for the quarter by 19%; however, a 10% increase in our reserves would have decreased our depletion expense for the quarter by 27%.

“Ceiling” limitation test — The most likely factor to contribute to a ceiling test impairment is the price used to calculate the reserve limitation threshold. A significant reduction in the prices at a future measurement date could trigger a full-cost ceiling impairment. At September 30, 2004, we had a cushion (i.e. the excess of the ceiling over our capitalized costs) of $71.4 million. A 10% decrease in prices used would have decreased our cushion by 18%, but a 10% increase in prices would have increased our cushion by 19%. Our hedging program would serve to mitigate some of the impact of any price decline. Our hedges did not impact the ceiling test this quarter, and would not have if the price was 10% lower as these prices were within the collars, but had we increased the price by 10% the price would have exceeded our hedge caps and therefore resulted in a decrease in the ceiling of $0.5 million. Another likely factor to contribute to a ceiling test impairment is a revised estimate of reserves. A 10% decrease in reserve volume would have decreased our cushion by 18% and a 10% increase in reserve volumes would have increased our cushion by 20%.

Nature of Critical Estimate Item: Unproved Property Impairment — We have elected to use the full-cost method to account for our oil and gas activities. 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 quarterly 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.

Assumptions/Approach Used: At September 30, 2004, we had $9.1 million allocated to unproved property. This allocation is based on the estimation by the technical team of whether the property has potential attributable reserves. Therefore, the assessment made by our technical team of the potential reserves will determine whether costs are moved from the unproved category to the full-cost pool for depletion or whether an impairment is taken.

Effect if different assumptions used: A 10% increase or decrease in the unproved property balance (i.e. transfer to full-cost pool) would have increased or decreased our depletion expense by 2% for the quarter ended September 30, 2004.

Nature of Critical Estimate Item: 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. Previously, the costs associated with this activity were capitalized to the full-cost pool and charged to income through depletion. We adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” 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 estimate asset retirement costs for all of our assets, inflation adjust those costs to the forecast abandonment date, discount that amount using a credit-adjusted-risk-free rate back to the date we acquired the asset or obligation to retire the asset and record an ARO liability in that amount with a corresponding addition to our asset value. We then accrete the liability quarterly using the period-end effective credit-adjusted-risk-free rate. As new wells are drilled or purchased, their initial asset retirement cost and liability is calculated and recorded. Should either the estimated life or the estimated abandonment costs of a property change upon our quarterly review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost (included in the full-cost pool); therefore, abandonment costs will almost always approximate the estimate. When wells are sold the related liability and asset costs are removed from the Balance Sheet.

Assumptions/Approach Used: 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. Inherent in the estimate of the present value calculation of our AROs are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted-risk-free-rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments.

Effect if different assumptions used: Since there are so many variables in estimating AROs, we attempt to limit the impact of management’s judgment on certain of these variables by using input of qualified third parties. We engage an independent engineering firm to evaluate our properties annually. We use the remaining estimated useful life from the year-end reserve reports by our independent reserve engineer in estimating when abandonment could be expected for each property. We utilize a three-year average rate for inflation to diminish any significant volatility that may be present in the short term. We expect to see our calculations impacted significantly if interest rates move from their current lows, as the credit-adjusted-risk-free rate is one of the variables used on a quarterly basis. Our technical team developed a standard cost estimate based on historical costs, industry quotes and depth of wells. Unless we expect a well’s plugging to be significantly different than a normal abandonment, we use this estimate. The resulting estimate, after

application of a discount factor and some significant calculations, could differ from actual results, despite all our efforts to make an accurate estimate.

Nature of Critical Estimate Item: Income Taxes — In accordance with the accounting for income taxes under SFAS No. 109, we have recorded a deferred tax asset to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. There are several items that result in deferred tax asset impact to the balance sheet, but the largest of which is income taxes and the impact of net operating loss (“NOL”) carryforwards. We routinely assess the realizability of our NOL carryforwards that resulted from substantial income tax deductions, prior year losses and acquisitions. We consider future taxable income in making such assessments. 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, it is reduced by a valuation allowance.

Assumptions/Approach Used: 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 NOL carryforwards.

Effect if different assumptions used: We have engaged an independent public accounting firm to assist us in applying the numerous and complicated tax law requirements. However, despite our attempt to make an accurate estimate, the ultimate utilization of our NOL carryforwards is highly dependent upon our actual production and the realization of taxable income in future periods. If we estimate that some or all of our NOL carryforwards are more likely than not going to expire or otherwise not be utilized to reduce future tax, we would record a valuation allowance to remove the benefit of those NOL carryforwards from our financial statements.

Nature of Critical Estimate Item: Derivative & Hedging Activities — 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 all of these transactions are economic hedges of price risk, different accounting treatment may apply depending on if they qualify for cash flow hedge accounting. In accordance with SFAS No. 133, all transactions are recorded on the balance sheet at fair value.

Hedge Contracts — We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used for hedging 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. The ongoing measurement of effectiveness determines whether the change in fair value is deferred through other comprehensive income (“OCI”) on the balance sheet or recorded immediately in revenue on the income statement. The effective portion of the changes in the fair value of hedge contracts is recorded initially in OCI. When the hedged production is sold, the realized gains and losses on the hedge contracts are removed from OCI and recorded in revenue. Ineffective portions of the changes in the fair value of the hedge contracts are recognized in revenue as they occur. While the hedge contract is outstanding, the ineffective gain or loss may increase or decrease until settlement of the contract.

Derivative Contracts — For transactions not accounted for using cash flow hedge accounting, the change in the fair value of the derivative contract is reflected in revenue immediately, i.e. not deferred through OCI, and there is no measurement of effectiveness.

Assumptions/Approach Used: Estimating the fair values of derivative instruments requires complex calculations, including the use of a discounted cash flow technique, estimates of risk and volatility, and subjective judgment in selecting an appropriate discount rate. In addition, the calculations use future market commodity prices, which although posted for trading purposes, are merely the market consensus of

forecasted price trends. The results of the fair value calculations cannot be expected to represent exactly the fair value of our commodity hedges. We currently obtain the fair value of our positions from our counterparties. Our practice of relying on our counterparties who are more specialized and knowledgeable in preparing these complex calculations reduces our management’s input.

Effect if different assumptions used: At September 30, 2004, 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 our derivative financial instrument to increase or decrease by approximately $217,400.

Results of Operations

This section includes discussion of our results of operations for the three-month and nine-month periods ended September 30, 2004 as compared to the same periods of the prior year. 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.

Third Quarter 2004 Compared to the Third Quarter 2003

Revenue and Production

Total revenue increased 49% from the third quarter of 2003 to the comparable 2004 period. For the three months ended September 30, 2004 and 2003, our product mix contributed the following percentages of production and revenues:

	REVENUES(1)				PRODUCTION
	2004		2003		2004		2003
Natural Gas (Mcf)	89	%	84	%	74	%	79	%
Natural gas liquids (Bbls)	8	%	6	%	14	%	13	%
Crude oil (Bbl)	3	%	10	%	12	%	8	%
Total (Mcfe)	100	%	100	%	100	%	100	%

(1) Includes effect of hedging and derivative transactions.

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

								2004 Period Compared to 2003 Period
	Three Months Ended													%
	September 30,							Increase						Increase
	2004				2003				(Decrease)					(Decrease)
Production Volumes:
Natural gas (Mcf)	2,077,791				1,717,559				360,232					21	%
Natural gas liquids (Bbls)	63,857				49,308				14,549					30	%
Oil and condensate (Bbls)	56,415				29,918				26,497					89	%
Natural gas equivalent (Mcfe)	2,799,423				2,192,915				606,508					28	%
Average Sales Price:
Natural gas ($ per Mcf)(1)	$		5.74		$	4.84			$		0.89			18	%
Natural gas liquids ($ per Bbl)	$		16.27		$	10.05			$		6.22			62	%
Oil and condensate ($ per Bbl)(1)	$		39.17		$	30.18			$		8.99			30	%
Natural gas equivalent ($ per Mcfe)(1)	$		5.42		$	4.43			$		0.99			22	%
Natural gas equivalent ($ per Mcfe)(2)	$		4.73		$	4.06			$		0.67			17	%
Operating Revenue:
Natural gas (1)	$	11,933,309			$	8,320,546			$			3,612,763		43	%
Natural gas liquids	1,038,811				495,448				543,363					110	%
Oil and condensate (1)	2,209,754				903,014				1,306,740					145	%
Loss on hedging and derivatives	(1,939,409			)	(824,470		)		(1,114,939				)	(135	)%
Total	$	13,242,465			$	8,894,538			$	4,347,927				49	%

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

(2) 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, excluding hedging activity, increased 43% for the three months ended September 30, 2004 over the same period in 2003 due to significantly higher production and higher realized prices. Average natural gas production increased 21% from 18.7 MMcf/D in the three months ended September 30, 2003 to 22.6 MMcf/D in the comparable 2004 period due to production from new wells drilled and acquired, primarily in 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 $1.7 million (based on 2003 comparable period pre-hedge prices). Excluding the effect of hedges, the average natural gas sales price for production in the third quarter of 2004 was $5.74 per Mcf compared to $4.85 per Mcf for the same period in 2003. This increase in average price received resulted in increased revenue of approximately $1.9 million (based on current year production).

Revenue from the sale of NGLs increased 110% for the three months ended September 30, 2004 over the same period in 2003. Production volumes for NGLs increased 30%, from 536 Bbls/D for the three months ended September 30, 2003 to 694 Bbls/D for the three months ended September 30, 2004 due primarily to increased production from new wells drilled and acquired. The increase in NGL production increased revenue by approximately $146,000 (based on 2003 comparable period average prices). Higher average realized prices for the three months ended September 30, 2004 resulted in an increase in revenue of approximately $397,000 (based on current year production). The average realized price for NGLs for the three months ended September 30, 2004 was $16.27 per barrel compared to $10.05 per barrel for the same period in 2003.

Revenue from the sale of oil and condensate, excluding derivative activity, increased 145% for the three months ended September 30, 2004 as compared to the comparable prior year period in 2003 due to increased production and realized prices. Production volumes for oil and condensate increased 89% to 613 Bbls/D for the three months ended September 30, 2004 compared to 325 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 $800,000 (based on 2003 comparable period average prices). The average realized price for oil and condensate before the derivative losses for the three months ended September 30, 2004 was $39.17 per barrel compared to $30.18 per barrel in the same period of 2003. These higher average prices for the third quarter of 2004 resulted in an increase in revenue of approximately $507,000 (based on current year production).

Losses on hedging and derivatives increased 135% for the three months ended September 30, 2004 over the same period in 2003 due to the change in the fair market value of the outstanding derivative contracts as a result of volatile commodity prices and cash settlements on expiring contracts. Oil and condensate revenues were decreased by realized and unrealized losses on our oil derivatives. For the three months ended September 30, 2004 we recorded $307,437 of realized losses on oil derivatives settlements and $1.4 million of unrealized losses representing the change in the mark-to-market fair value of our outstanding oil derivative contracts. We did not apply hedge accounting to these transactions. See Note 7 to our Consolidated Financial Statements. These losses account for a $30.87 per barrel decrease in the realized oil price for the three months ended September 30, 2004 from $39.17 per barrel to $8.30 per barrel. There was no oil

derivative activity during the three months ended September 30, 2003. Should the crude oil prices decrease from the current levels, we would realize lower revenues, but our oil derivative losses would also decrease and could possibly result in a gain position. For the three months ended September 30, 2004, we recognized $197,800 of the premium paid for a natural gas hedge entered into in 2003. This loss decreased the effective natural gas sales price by $0.10 per Mcf. Included within natural gas revenue for the three months ended September 30, 2003 was $824,470 representing realized losses from hedging contract settlements. These losses decreased the effective natural gas sales price by $0.48 per Mcf for the three months ended September 30, 2003. Should natural gas prices decrease from the current high levels, this could materially affect our revenues that are not hedged.

Costs and Operating Expenses

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

	Three Months Ended						2004 Period Compared to 2003 Period
	September 30,						Increase			% Increase
	2004				2003		(Decrease)			(Decrease)
Lease operating expenses	$	1,176,732			$	597,550	$	579,182		97	%
Severance and ad valorem taxes	891,194				561,787		329,407			59	%
Depreciation, depletion, amortization and accretion:
Oil and gas property and equipment	5,315,004				3,572,173		1,742,831			49	%
Other assets	103,815				140,062		(36,247		)	(26	)%
ARO accretion	27,627				14,799		12,828			87	%
General and administrative expenses:
Deferred compensation — repriced options	(153,808			)	—		(153,808		)	*
Deferred compensation — restricted stock	143,500				93,604		49,896			53	%
Other general and administrative expenses	1,844,062				1,157,259		686,803			59	%
	9,348,126				6,137,234		3,210,892			52	%
Other expense, net	50,065				120,359		(70,294		)	(58	)%
Total	$		9,398,191		$	6,257,593	$	3,140,598		50	%

* Not meaningful

Lease operating expenses for the three months ended September 30, 2004 increased 97% over the same period of 2003. The 2003 acquisition of properties in South Texas and the Miller merger contributed 61% of the increase in costs. Wells drilled since the third quarter of 2003 further increased the costs for the third quarter of 2004 compared to the prior year. We have experienced some cost increases on outside operated properties on the O’Connor Ranch field and on operated properties at Gato Creek. In addition, the Miller and States properties acquired in 2003 have slightly higher costs than our other properties. These cost increases have led to an increase in lease operating expenses to $0.42 per Mcfe for the three months ended September 30, 2004 from $0.27 per Mcfe for the same prior year period.

Severance and ad valorem taxes for the three months ended September 30, 2004 increased 59% from the third quarter of 2003. Severance tax expense for the third quarter of 2004 was 72% higher than the comparable prior year period as a result of higher revenue. Our severance tax expense is levied on our oil and gas revenue dollars (excluding hedging and derivative impact), so if commodity prices remain high, we expect to continue to incur

higher severance tax expense. For the three months ended September 30, 2004, severance tax expense was approximately 5.2% 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 were comparable in the third quarter of 2003 and the third quarter of 2004. On an equivalent basis, severance and ad valorem taxes averaged $0.32 per Mcfe and $0.26 per Mcfe for the three months ended September 30, 2004 and 2003, respectively.

Depletion, depreciation, and amortization (“DD&A”) and accretion expense for the three months ended September 30, 2004 totaled $5.4 million compared to $3.7 million for the three months ended September 30, 2003. Depletion on our oil and natural gas properties increased 49% for the third quarter of 2004 compared to the same period of 2003 due to an increase in production levels and in the unit-of-production depletion rate from $1.63 in 2003 as compared to $1.90 in 2004. The increase in depletion expense from the higher production levels in the third quarter of 2004 as compared to the same period of 2003 resulted in an increase in expense of approximately $988,000. The increase in rate for the third quarter of 2004 compared to 2003 added approximately $755,000 in depletion expense. Our rate has increased due to increased spending on our drilling program with disproportionate reserve additions. Depreciation of furniture and fixtures decreased 26% compared to the prior year third quarter due to several larger depreciable assets that became fully depreciated by year-end 2003 and are not currently contributing to expense. Accretion expense associated with our asset retirement obligations for the three months ended September 30, 2004 increased 87% over 2003 for the new obligations incurred from the Miller merger, South Texas property acquisition and new wells drilled.

Total G&A for the three months ended September 30, 2004 was $1.8 million, an increase of 47% compared to the prior year third quarter total of $1.3 million. Pursuant to FIN 44 discussed in Note 1 to the consolidated financial statements, 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 credit of $153,808 was incurred for the three months ended September 30, 2004 compared to no activity in the comparable prior year period. Amortization related to restricted stock awards granted over the past three years totaled $143,500 and $93,604, respectively, for the three months ended September 30, 2004 and 2003. The increase relates to new grants that have occurred since 2003. Other G&A for the three months ended September 30, 2004, which does not include the deferred compensation expenses discussed above, totaled $1.8 million, a 59% increase from the comparable 2003 period total of $1.2 million. The increase in other G&A was attributable to higher salaries and benefits, due in part to higher staffing levels, as well as higher professional fees related to Sarbanes-Oxley regulatory requirements and the costs of other work by our new independent accountants. For the three months ended September 30, 2004 and 2003, overhead reimbursement fees reduced G&A costs by $49,716 and $30,798, respectively. Capitalized G&A costs further reduced other G&A by $552,070 and $571,667, respectively, for the three months ended September 30, 2004 and 2003. Other G&A on a unit of production basis for the three months ended September 30, 2004 was $0.66 per Mcfe compared to $0.53 per Mcfe for the comparable 2003 period.

Included in other income (expense) was interest expense of $22,204 for the three months ended September 30, 2004 compared to $128,651 in the same 2003 period. The decrease is due to increased capitalization of interest and lower interest rates. Interest expense, including facility fees, was $188,843 for the third quarter of 2004 on weighted average debt of $19.0 million compared to interest expense of $194,336 on weighted average debt of approximately $21.5 million for the third quarter of 2003. Capitalized interest for the three months ended September 30, 2004 totaled $166,639 compared to $65,685 in the same prior year period due to our higher unproved property balance at period end. We also recorded amortization of deferred loan costs of $35,948 during the third quarter of 2004 related to our amended credit facility.

An income tax provision was recorded for the three months ended September 30, 2004 and 2003 of $1.4 million and $0.9 million, respectively. The increase resulted from higher pre-tax income in 2004 as compared to 2003.

For the three months ended September 30, 2004, we had net income of $2.5 million, or $0.19 basic earnings per share and $0.18 diluted earnings per share, as compared to net income of $1.7 million, or $0.18 basic and $0.17 diluted earnings per share in the comparable 2003 period. Basic weighted average shares outstanding increased slightly for stock option exercises for the three months ended September 30, 2004 and 2003. The significant increase in shares outstanding between September 30, 2004 and 2003 was due primarily to the issuance

of 2.6 million shares of stock in the merger with Miller in December 2003 as well as the exercise of stock options and warrants and the vesting and issuance of restricted stock during the fourth quarter 2003 and first nine months of 2004.

Nine Months Ended September 30, 2004 Compared to the Nine Months Ended September 30, 2003

Revenue and Production

Total revenue increased 89% from the third quarter of 2003 to the comparable 2004 period. For the nine months ended September 30, 2004, our product mix contributed the following percentages of production and revenues:

	REVENUES (1)				PRODUCTION
	2004		2003		2004		2003
Natural Gas (Mcf)	84	%	81	%	76	%	76	%
Natural gas liquids (Bbls)	7	%	7	%	13	%	15	%
Crude oil (Bbl)	9	%	12	%	11	%	9	%
Total (Mcfe)	100	%	100	%	100	%	100	%

(1) Includes effect of hedging and derivative transactions.

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

							2004 Period Compared to 2003 Period
	Nine Months Ended								%
	September 30,						Increase		Increase
	2004			2003			(Decrease)		(Decrease)
Production Volumes:
Natural gas (Mcf)	6,797,836			4,195,998			2,601,838		62	%
Natural gas liquids (Bbls)	190,944			131,629			59,315		45	%
Oil and condensate (Bbls)	156,075			84,744			71,331		84	%
Natural gas equivalent (Mcfe)	8,879,950			5,494,236			3,385,714		62	%
Average Sales Price:
Natural gas ($ per Mcf)(1)	$	5.67		$	5.59		$	0.08	1	%
Natural gas liquids ($ per Bbl)	$	15.40		$	12.88		$	2.52	20	%
Oil and condensate ($ per Bbl)(1)	$	36.70		$	32.47		$	4.23	13	%
Natural gas equivalent ($ per Mcfe)(1)	$	5.32		$	5.08		$	0.24	5	%
Natural gas equivalent ($ per Mcfe)(2)	$	5.06		$	4.32		$	0.74	17	%
Operating Revenue:
Natural gas (1)	$	38,535,571		$	23,440,741		$	15,094,830	64	%
Natural gas liquids	2,939,992			1,695,787			1,244,205		73	%
Oil and condensate (1)	5,728,237			2,751,525			2,976,712		108	%
Loss on hedging and derivatives	(2,299,274		)	(4,160,350		)	1,861,076		45	%
Total	$	44,904,526		$	23,727,703		$	21,176,823	89	%

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

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

Natural gas revenue, excluding hedging activity, increased 64% for the nine months ended September 30, 2004 as compared to the same period in 2003 due to significantly higher production. Average natural gas production increased 62% from 15.4 MMcf/D in the nine months ended September 30, 2003 to 24.8 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 $14.5 million (based on 2003 comparable period pre-hedge prices). Excluding the effect of hedges, the average natural gas sales price for production in the first nine months of 2004 was $5.67 per Mcf compared to $5.59 per Mcf for the same period in 2003. This increase in average price received resulted in increased revenue of approximately $560,000 (based on current year production).

Revenue from the sale of NGLs for the nine months ended September 30, 2004 increased 73% from the same 2003 period due to both increased production and higher realized prices. Production volumes for NGLs increased 45%, from 482 Bbls/D for the nine months ended September 30, 2003 to 697 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 approximately $764,000 (based on 2003 comparable period average prices). Higher average realized prices for the nine months ended September 30, 2004 resulted in an increase in revenue of approximately $480,000 (based on current year production).

Revenue from the sale of oil and condensate, excluding derivative activity, for the nine months ended September 30, 2004 increased 108% from the comparable prior year period due primarily to production from our Miller properties acquired in late 2003. Production volumes for oil and condensate increased 84% to 570 Bbls/D for the nine months ended September 30, 2004 compared to 310 Bbls/D for the same period in 2003. The increase in oil and condensate production resulted in an increase in revenue of approximately $2.3 million (based on 2003 comparable period pre-derivative prices). Excluding the effect of the oil derivatives, the average realized price for oil and condensate for the nine months ended September 30, 2004 was $36.70 per barrel compared to $32.47 per barrel in the same period of 2003. This higher average price for the first nine months of 2004 resulted in an increase in revenue of approximately $661,000 (based on current year production).

Losses on hedging and derivatives decreased 45% for the nine months ended September 30, 2004 over the same period in 2003 due to the change in fair market value of our outstanding derivative contracts as a result of volatile commodity prices and cash settlements on expiring contracts. For the nine months ended September 30, 2004, we realized natural gas hedge losses of $222,000. In addition, we recognized $411,650 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 nine months ended September 30, 2003 was $4.2 million representing realized losses from hedging activity. These losses decreased the effective natural gas sales price by $0.99 per Mcf for the nine months ended September 30, 2003. For the nine months ended September 30, 2004, we realized crude oil derivative losses of $410,713. In addition, we recorded mark-to-market unrealized losses on the change in fair value of the outstanding oil derivative contracts of $1.3 million for the nine months ended September 30, 2004 as compared to none in 2003. We did not apply hedge accounting to these transactions. See Note 7 to our Consolidated Financial Statements. The net loss related to the oil collars decreased the average price per barrel by $10.67. Should the crude oil prices decrease from the current highs, we would realize lower revenues, but our oil derivative losses would also decrease and could possibly result in a gain position.

Costs and Operating Expenses

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

						2004 Period Compared to 2003 Period
	Nine Months Ended									%
	September 30,					Increase				Increase
	2004			2003		(Decrease)				(Decrease)
Lease operating expenses	$		3,601,898	$	1,743,352	$		1,858,546		107	%
Severance and ad valorem taxes	3,146,116			1,602,846		1,543,270				96	%
Depreciation, depletion, amortization and accretion:
Oil and gas property and equipment	15,467,305			8,803,799		6,663,506				76	%
Other assets	282,815			485,792		(202,977			)	(42	)%
ARO accretion	80,128			44,652		35,476				79	%
General and administrative expenses:
Deferred compensation — repriced options	1,294,677			—		1,294,677				*
Deferred compensation — restricted stock	354,600			270,043		84,557				31	%
Other general and administrative expenses	5,476,342			3,844,277		1,632,065				42	%
	29,703,881			16,794,761		12,909,120				77	%
Other expense, net	332,101			456,646		(124,545			)	(27	)%
Total	$	30,035,982		$	17,251,407	$	12,784,575			74		%

* Not meaningful

Lease operating expenses for the nine months ended September 30, 2004 increased 107% compared to the same period of 2003. Current year results were impacted by the drilling of 38 wells since the third quarter of 2003 as well as increased production of 62% over 2003, the Miller merger, acquisitions of properties from third parties, increased costs at O’Connor Ranch, as well as salt water disposal costs at the Thibodeaux well for the first half of the year. These cost increases have lead to an increase in lease operating expenses to $0.41 per Mcfe for the nine months ended September 30, 2004 from $0.32 per Mcfe in the comparable prior year period.

Severance and ad valorem taxes for the nine months ended September 30, 2004 increased 96% over 2003. Severance tax expense for the first nine months of 2004 of $2.8 million was 111% higher than the comparable prior year period as a result of higher revenue. Our severance tax expense is levied on our oil and gas revenue dollars (excluding hedging and derivative impact), so if commodity prices remain high, we expect to continue to incur higher severance tax expense. For the nine months ended September 30, 2004, severance tax expense was approximately 6.0% 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 26% from $274,405 in the first nine months of 2003 to $345,502 in the first nine months of 2004. On an equivalent basis, severance and ad valorem taxes averaged $0.35 per Mcfe and $0.29 per Mcfe for the nine months ended September 30, 2004 and 2003, respectively.

Depletion, depreciation, and amortization (“DD&A”) and accretion expense for the nine months ended September 30, 2004 totaled $15.8 million compared to $9.3 million for the same period in 2003. Depletion on our oil and natural gas properties increased 76% for the first nine months of 2004 compared to the same period of 2003. Depletion expense on a unit of production basis for the nine months ended September 30, 2004 was $1.74 per Mcfe, compared to a 2003 rate of $1.60 per Mcfe for the same period. The increase in depletion expense was due primarily to the higher production levels in the first nine months of 2004 as compared to the same period of 2003. Depreciation of furniture and fixtures for the nine months ended September 30, 2004 decreased 42% compared to the prior year. In the first quarter of 2003, we moved offices resulting in accelerated depreciation of leasehold costs associated with our prior office building lease. We recorded accretion expense associated with our asset retirement obligation for the nine months ended September 30, 2004 with an increase of 79% over the comparable 2003 period due to the new obligations incurred for the acquisition, merger and new wells drilled since then.

Total G&A for the nine months ended September 30, 2004 was $7.1 million, an increase of 73% compared to the comparable prior year total of $4.1 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 of $1.3 million was incurred for the nine months ended September 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 $354,600 and $270,043, respectively, for the nine months ended September 30, 2004 and 2003. Other G&A for the nine months ended September 30, 2004, which does not include the deferred compensation expenses discussed above, totaled $5.5 million, a 42% increase from the comparable 2003 period total of $3.8 million. The increase in other G&A was attributable to higher salaries and benefits, due in part to higher staffing levels, as well as higher legal and professional fees and higher investor relation costs. In addition, we incurred costs associated with the Miller acquisition of approximately $233,000. For the nine months ended September 30, 2004 and 2003, overhead reimbursement fees reduced G&A costs by $179,762 and $87,033, respectively. Capitalized G&A costs further reduced other G&A by $1.6 million and $1.2 million, respectively, for the nine months ended September 30, 2004 and 2003. Other G&A on a unit of production basis for the nine months ended September 30, 2004 was $0.62 per Mcfe compared to $0.70 per Mcfe for the comparable 2003 period.

Included in other income (expense) was interest expense of $241,887 for the nine months ended September 30, 2004 compared to $470,086 in the same 2003 period. Interest expense, including facility fees, was $620,005 for the first nine months of 2004 on weighted average debt of $19.8 million compared to interest expense of $659,783 on weighted average debt of approximately $21.4 million for the first nine months of 2003. Capitalized interest for the nine months ended September 30, 2004 totaled $378,118 compared to $189,697 in the same prior year period. At September 30, 2004, our unproved property balance was $9.1 million compared to $5.0 million at December 31, 2003 and $7.6 million at September 30, 2003, resulting in the higher capitalized interest for the 2004 period. We also reported deferred loan costs of $106,332 during the first nine months of 2004. We amended our credit facility after the Miller merger resulting in loan costs of $425,364 that will be amortized over a three-year period ending December 31, 2006.

An income tax provision was recorded for the nine months ended September 30, 2004 and 2003 of $5.2 million and $2.3 million, respectively. The increase is primarily due to the increase in pre-tax income. As of December 31, 2003, we had estimated cumulative NOL carryforwards for federal income tax purposes of approximately $50.1 million, including $17.4 million of NOL carryforwards acquired in the Miller merger, 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 nine months ended September 30, 2004, we had net income of $9.6 million, or $0.75 basic earnings per share and $0.71 diluted earnings per share, as compared to net income of $3.8 million, or $0.40 basic and $0.39 diluted earnings per share in the comparable 2003 period. Basic weighted average shares outstanding increased from approximately 9.5 million for the nine months ended September 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 stock options, the exercise of warrants and the vesting and issuance of restricted stock during 2003 and the first nine months 2004.

Liquidity

Our primary ongoing source of capital is the cash flow generated from our operating activities supplemented by borrowings under our credit facility. Net cash generated from operating activities is a function of production volumes, commodity prices, which are inherently volatile and unpredictable, operating efficiency and capital spending. Our business, as with other extractive industries, is a depleting one in which each gas equivalent unit produced must be replaced or we, and a critical source of our future liquidity, will shrink. Our overall production decline is approximately 25% 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 attempt to mitigate the price risk with our hedging program. 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.

Some significant changes to working capital may also affect our liquidity in the short term. The increase in accrued capital expenditures at September 30, 2004 accounts for most of the increase in accrued liabilities at September 30, 2004. These accruals represent liabilities incurred from the increase in exploratory and development activities in the third quarter of 2004 and will require payment as soon as we receive invoices from our vendors. Therefore, we expect our short-term cash outflows for the fourth quarter to increase as these liabilities come due. At September 30, 2004, we had 12 wells in various stages of drilling and completion.

Our liability related to commodity derivatives has increased to $2.3 million, as commodity prices increased, contributing to the working capital reduction. The derivative financial instrument liability represents the amount by which strip commodity prices exceed the price caps on our contracts. Should commodity prices decrease, the liability will decline, and the unrealized losses on the income statement and in other comprehensive income will reduce or could possibly result in gains. Since hedges and derivatives are settled out of the receipts from the sale of production, we anticipate having adequate cash inflows to settle any hedge payments when they come due while maintaining revenue near the derivative price.

After considering the impact of these working capital changes and our forecasts of future results of operations, we believe that cash flows from operating activities, as supplemented by borrowings on our line of credit, combined with our ability to control the timing of the majority of our future exploration and development requirements will provide us with the flexibility and liquidity to meet our planned capital requirements for 2004. In addition, our revolving credit facility has $23.0 million available for general corporate purposes, including exploratory and developmental drilling and acquisitions of oil and gas properties.

Net Cash Provided By Operating Activities

Cash flows provided by operating activities were $40.5 million for the nine months ended September 30, 2004 compared to $16.3 million for the nine months ended September 30, 2003. The significant increase in cash flows provided by operating activities for the nine months ended September 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. Due to the inflated commodity pricing for crude oil, the impact related to the derivatives to the first nine months of 2004 has been negative, as the prices have exceeded the highs we expected. We have realized the benefit of these high prices on our crude oil production, but also realized the negative impact from $410,713 of cash settlements on our crude oil derivatives. We have also realized $222,000 of cash settlements on our natural gas hedges. Overall, oil and gas production revenue increased with a 62% increase in production and a 17% increase in the average price received for our production.

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 $42.1 million in investing activities during the first nine months of 2004. Capital expenditures of $37.0 million were attributable to the drilling of 30 gross wells, 23 of which were successful, including 2, which were being tested at quarter end. Leasehold acquisitions, including seismic data and other geological and geophysical expenditures totaled $2.6 million and acquisition costs totaled $0.1 million for the nine months ended September 30, 2004. The remaining capital expenditures were associated with computer hardware and office equipment. Proceeds from the sale of oil and gas properties totaled $45,000 during the first nine months of 2004. During the nine months ended September 30, 2003, we used $25.2 million in investing activities. Capital expenditures of $25.5 million for the nine months ended September 30, 2003, were partially offset by $330,096 in

proceeds from the sale of interests in certain oil and gas properties, including the sale of our interest in the Essex I and Essex II joint ventures.

We currently anticipate capital expenditures in 2004 to be approximately $52 million. Approximately $43.3 million is allocated to our expected drilling and production activities; $4.3 million is allocated to land and seismic activities; and $4.6 million relates to capitalized interest and G&A and other. We plan to fund these expenditures from expected cash flow from operations plus some incremental borrowings. We have not explicitly budgeted for acquisitions; however, we have spent considerable effort evaluating acquisition opportunities during 2004 and expect to continue. We have signed a Purchase and Sale Agreement with Contango to purchase onshore South Texas properties for approximately $50 million (before purchase price adjustments). We expect to fund this acquisition and any others that may occur in the near term through traditional oil and gas reserve-based bank debt, and the issuance of common stock and, if required, through additional debt and equity financings. We currently have $23.0 million of unused borrowing capacity under our credit facility.

Net Cash Provided By Financing Activities

Cash flows provided by financing activities totaled $2.7 million for the nine months ended September 30, 2004. Net borrowings of $1.0 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 $2.2 million in proceeds from the issuance of common stock related to stock options and warrants exercised in the first nine months of 2004. Cash flows provided by financing activities totaled $9.6 million for the nine months ended September 30, 2003, and included borrowings of $10.7 million and payments of $1.2 million under our credit facility as well as $84,603 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 and borrowing supplements from our line of credit 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.

Contractual Cash Obligations

In July 2004, we expanded our corporate office space and increased our lease obligation for a half floor within our current office building. This increases our total obligation from $4.1 million to $5.8 million over the same lease term. There were no other material changes, outside the ordinary course of our business, in other contractual obligations since December 31, 2003.

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 from internally generated cash flows and any shortfalls are supplemented by borrowings under our credit facility. 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.

During 2003 and 2004, the rise in our stock price contributed to significant exercise of warrants and stock options, from which we have realized increased cash flows from financing activities. During November and December of 2003, we issued 375,000 shares of common stock in connection with the exercise of warrants that resulted in proceeds to us of approximately $2.0 million. As of December 31, 2003, 45,000 of the warrants were

outstanding. On March 2, 2004, Mr. Elias, our Chairman and Chief Executive Officer, exercised the remaining warrants for 45,000 shares of common stock which resulted in proceeds to us of approximately $241,000. Increased activity in stock option and warrant exercises has also resulted in proceeds to us of approximately $1.9 million for the nine months ended September 30, 2004. We typically do not rely on proceeds from the exercise of warrants and stock options to sustain our business as they are unpredictable events.

We had cash and cash equivalents at September 30, 2004 of $2.5 million consisting primarily of short-term money market investments, as compared to $1.3 million at December 31, 2003. Working capital was ($6.3) million as of September 30, 2004, as compared to $0.9 million at December 31, 2003. Available borrowing capacity under our facility was $23.0 million at September 30, 2004 and we had $150 million remaining under our shelf registration statement (see discussion below).

In the event such capital resources are not available to us, our drilling and other activities may be curtailed, which may adversely affect our ability to replace our reserves and production streams.

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 September 30, 2004, $22.0 million in borrowings were outstanding under the Credit Facility and our interest rate was 4.06%. 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. Effective November 1, 2004, the Credit Facility’s borrowing base was increased from $45.0 million to $48.0 million.

• The EBITDAX to Interest Expense ratio requires that the ratio of(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.

Consolidated EBITDAX is a component of negotiated covenants with our lender 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 September 30, 2004, we had $150 million remaining for issuance under the shelf registration. Our ability to utilize our shelf registration statement for the purpose of issuing, from

time to time, any combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities 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.

Risk Management Activities — Derivatives & Hedging

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 limit 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 arrangements, to the extent we enter into any, apply to only a portion of our production, 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. On a quarterly basis, our management sets all of our price-risk management policies, including volumes, types of instruments and counterparties. 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 price-risk management policies and trades.

Fair value of contracts outstanding at December 31, 2003	$		120,801
Contracts realized or otherwise settled during the period	(37,688			)
Fair value of new contracts when entered into during 2004	(1,930,329			)
Changes in fair values attributable to changes in valuation techniques and assumptions	—
Other changes in fair values	(429,747			)
Fair values of contracts outstanding at September 30, 2004	$	(2,276,963		)

The following table details the fair value of our commodity-based derivative and hedging contracts by year of maturity and valuation methodology as of September 30, 2004.

	Fair Value of Contracts at September 30, 2004
Source of Fair Value	Maturity less than 1 year			Maturity 1-3 years			Maturity 4-5 years		Maturity in excess of 5 years		Total fair value
Prices actively quoted	—			—			—		—		—
Prices provided by other external sources	(2,159,880		)	(117,083		)	—		—		(2,276,963		)
Prices based on models and other valuation methods	—			—			—		—		—
Total	$	(2,159,880	)	$	(117,083	)	$	—	$	—	$	(2,276,963	)

Tax Matters

At December 31, 2003, we had estimated cumulative NOL carryforwards for federal income tax purposes of approximately $50.1 million, including $17.4 million of NOL’s acquired in the Miller merger, that will begin to expire in 2012. We currently anticipate that all of these NOL’s will be utilized in connection with federal income taxes payable in the future. Our ability to fully utilize the NOL’s 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.

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. The FASB continued deliberations throughout the third quarter and expects to issue a final statement in the fourth quarter of 2004. As proposed, this statement would be effective for the Company on January 1, 2005. We are currently evaluating the impact that may result from adoption of this proposed statement.

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 September 30, 2004 outstanding borrowings and a floating interest rate of 4.06%, a 10% change in interest rates would result in an increase or decrease of interest expense of approximately $85,300 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 nine months of 2004, we put in place five additional natural gas collars and two crude oil collars covering 2004 and 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. The following is a list of contracts outstanding during the nine months ended September 30, 2004

Transaction Date

Transaction Type

Beginning

Ending

Price Per Unit

Volumes Per Day

Natural Gas:

12/03

Natural Gas Collar

(1)

01/01/04

03/31/04

$4.50-$7.05

5,000

08/03

Natural Gas Collar

(1)(2)

04/01/04

09/30/04

$4.50-$6.00

10,000

08/03

Natural Gas Collar

(1)(2)

01/01/04 10/01/04

03/31/04 12/31/04

$4.50-$7.00

10,000

02/04

Natural Gas Collar

(1)

04/01/04

09/30/04

$4.50-$6.20

5,000

03/04

Natural Gas Collar

(1)

10/01/04

12/31/04

$4.50-$7.25

5,000

05/04

Natural Gas Collar

(1)

01/01/05

03/31/05

$5.00-$10.39

10,000

07/04

Natural Gas Collar

(1)

04/01/05

06/30/05

$5.00-$7.53

10,000

07/04

Natural Gas Collar

(1)

07/01/05

09/30/05

$5.00-$7.67

10,000

Crude Oil:

03/04

Crude Oil Collar

(3)

04/01/04

12/31/04

$30.00-$35.50

400

05/04(08/04)

Crude Oil Collar

(3)(4)

01/01/05

12/31/05

$35.00-$40.00

200/290

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

(4) In August 2004, the Company replaced the hedge contract that was outstanding at June 30, 2004 with a new contract that changes the volume and pricing terms. The put option is on 200 Bbl/D and the call option is on 290 Bbl/D. This transaction was completed at no additional cost to the Company.

At September 30, 2004, the fair value of the outstanding hedges was a liability of approximately $2.3 million. 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 $217,400.

ITEM 4. CONTROLS AND PROCEDURES

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

During the third quarter the agent reduced the proposed franchise tax deficiency adjustment to the Company and its subsidiaries to an aggregate of $467,000. The Company intends to continue to vigorously contest this proposed franchise tax assessment through appropriate administrative levels in the Comptroller’s Office. The next step in the administrative process is a hearing at the Comptroller’s Office scheduled for November 2004. Should the Company’s administrative appeals prove unsuccessful, the Company plans to seek further appellate relief through available judicial means. Due to its intention to continue to vigorously contest the proposed adjustments, the Company has not recognized any provision for the additional franchise taxes that would result from the proposed deficiency.

Item 2 - Unregistered Sale of Equity Securities and Use of Proceeds		None
Item 3 - Defaults Upon Senior Securities		None
Item 4 - Submission of Matters to a Vote of Security Holders		None
Item 5 - Other Information		None

Item 6 - Exhibits

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)).

2.3	—	Asset Purchase Agreement dated as of October 7, 2004 by and among Contango Step, L.P., Contango Oil and Gas Company, Edge Petroleum Exploration Company and Edge Petroleum Corporation (Incorporated by reference from exhibit 2.1 to the Company’s Form 8-K filed on October 12, 2004).

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	—	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)).

4.3	—	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).

4.4	—	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).

4.5	—	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)).

4.6	—	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)).

4.7	—	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)).

4.8	—	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).

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)).

2.3	—	Asset Purchase Agreement dated as of October 7, 2004 by and among Contango Step, L.P., Contango Oil and Gas Company, Edge Petroleum Exploration Company and Edge Petroleum Corporation (Incorporated by reference from exhibit 2.1 to the Company’s Form 8-K filed on October 12, 2004).

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	—	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)).

4.3	—	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).

4.4	—	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).

4.5	—	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)).

4.6	—	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)).

4.7	—	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)).

4.8	—	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.

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

Class		Outstanding at November 10, 2004
Common Stock		13,025,568


Part I. Financial Information
Item 1. Financial Statements:
Consolidated Balance Sheets as of September 30, 2004 and December 31, 2003
Consolidated Statements of Operations for each of the Three and Nine Months in the Periods Ended September 30, 2004 and September 30, 2003
Consolidated Statements of Cash Flows for each of the Nine Months in the Periods Ended September 30, 2004 and September 30, 2003
Consolidated Statements of Stockholders’ Equity as of September 30, 2004 and December 31, 2003
Notes to the Consolidated Financial Statements
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Qualitative and Quantitative Disclosures About Market Risk
Item 4. Controls and Procedures
Part II. Other Information
Item 1. Legal Proceedings
Item 2. Unregistered Sale of Equity Securities and Use of Proceeds
Item 3. Defaults Upon Senior Securities
Item 4. Submission of Matters to a Vote of Security Holders
Item 5. Other Information
Item 6. Exhibits
Signatures

		EDGE PETROLEUM CORPORATION, A DELAWARE CORPORATION (REGISTRANT)


Date	November 12, 2004	/s/ John W. Elias
		John W. Elias
		Chief Executive Officer and Chairman of the Board


Date	November 12, 2004	/s/ Michael G. Long
		Michael G. Long
		Senior Vice President and Chief Financial Officer