UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(MARK ONE)

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

For the quarterly period ended June 30, 2009

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

For the transition period from to

Commission file number 0-22149

EDGE PETROLEUM CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

Delaware		76-0511037
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

1301 Travis, Suite 2000
Houston, Texas		77002
(Address of Principal Executive Offices)		(Zip Code)

(713) 654-8960

(Registrant’s Telephone Number, Including Area Code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ¨ Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

¨ Large accelerated filer		x Accelerated filer

¨ Non-accelerated filer (Do not check if a smaller reporting company)		¨ Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No

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

Class		Outstanding at August 4, 2009
Common Stock		28,867,675

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EDGE PETROLEUM CORPORATION

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	Page No.
Part I. Financial Information
Item 1. Financial Statements (Unaudited):
Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008	3
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2009 and 2008	4
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008	5
Consolidated Statement of Stockholders’ Equity for the Six Months Ended June 30, 2009	6
Notes to the Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3. Qualitative and Quantitative Disclosures About Market Risk	56
Item 4. Controls and Procedures	57
Part II. Other Information
Item 1. Legal Proceedings	58
Item 1A. Risk Factors	59
Item 2. Unregistered Sale of Equity Securities and Use of Proceeds	60
Item 3. Defaults Upon Senior Securities	60
Item 4. Submission of Matters to a Vote of Security Holders	60
Item 5. Other Information	60
Item 6. Exhibits	61
Signatures	66

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EDGE PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

	June 30,			December 31,
	2009			2008
	(Unaudited)
	(in thousands, except share data)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	15,693		$	8,475
Accounts receivable, trade, net of allowance	9,864			14,548
Accounts receivable, joint interest owners and other, net of allowance	1,595			5,689
Derivative financial instruments	12,709			15,407
Other current assets	3,297			4,591

Total current assets	43,158			48,710

PROPERTY AND EQUIPMENT, net — full cost method of accounting for oil and natural gas properties (including unevaluated costs of $23.0 million and $16.4 million at June 30, 2009 and December 31, 2008, respectively)	220,259			307,059

OTHER ASSETS	613			1,828

TOTAL ASSETS	$	264,030		$	357,597

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable, trade	$	1,691		$	3,086
Accrued liabilities	7,948			8,779
Accrued interest payable	22			579
Current portion of debt	234,000			239,000
Asset retirement obligation	555			547

Total current liabilities	244,216			251,991

ASSET RETIREMENT OBLIGATION — long-term	6,181			6,011

OTHER NON-CURRENT LIABILITIES	102			102

DELIVERY COMMITMENT	1,993			2,005

Total liabilities	252,492			260,109

COMMITMENTS AND CONTINGENCIES (Note 13)

STOCKHOLDERS’ EQUITY
Preferred stock, $0.01 par value; 5,000,000 shares authorized; 2,875,000 issued and outstanding at June 30, 2009 and December 31, 2008	29			29
Common stock, $0.01 par value; 60,000,000 shares authorized; 28,867,366, and 28,833,546 shares issued and outstanding at June 30, 2009 and December 31, 2008, respectively	289			288
Additional paid-in capital	424,309			423,951
Retained deficit	(413,089		)	(326,780		)

Total stockholders’ equity	11,538			97,488

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	264,030		$	357,597

See accompanying notes to consolidated financial statements.

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EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in thousands, except per share amounts)
OIL AND NATURAL GAS REVENUE:
Oil and natural gas sales	$	11,674		$	49,060		$	24,672		$	96,076
Gain (loss) on derivatives	109			(56,598		)	11,177			(85,957		)
Total revenue	11,783			(7,538		)	35,849			10,119

OPERATING EXPENSES:
Oil and natural gas operating expenses	3,824			3,941			7,649			8,413
Severance and ad valorem taxes	1,257			3,297			2,348			5,482
Depletion, depreciation, amortization and accretion	7,549			21,522			17,628			48,893
Impairment of oil and natural gas properties	—			—			78,254			—
General and administrative expenses	4,919			5,152			9,514			9,212

Total operating expenses	17,549			33,912			115,393			72,000

OPERATING LOSS	(5,766		)	(41,450		)	(79,544		)	(61,881		)

OTHER INCOME AND EXPENSE:
Other income	5			32			12			101
Interest expense, net of amounts capitalized	(3,069		)	(2,284		)	(5,312		)	(6,508		)
Amortization of deferred loan costs	(539		)	(239		)	(1,465		)	(478		)

LOSS BEFORE INCOME TAXES	(9,369		)	(43,941		)	(86,309		)	(68,766		)

INCOME TAX BENEFIT	—			16,118			—			24,764

NET LOSS	(9,369		)	(27,823		)	(86,309		)	(44,002		)

Preferred Stock Dividends	—			(2,067		)	—			(4,133		)

NET LOSS TO COMMON STOCKHOLDERS	$	(9,369	)	$	(29,890	)	$	(86,309	)	$	(48,135	)

BASIC LOSS PER SHARE	$	(0.40	)	$	(1.04	)	$	(3.13	)	$	(1.68	)

DILUTED LOSS PER SHARE	$	(0.40	)	$	(1.04	)	$	(3.13	)	$	(1.68	)

BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING	28,867			28,652			28,854			28,609

DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING	28,867			28,652			28,854			28,609

See accompanying notes to consolidated financial statements.

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EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

	Six Months Ended June 30,
	2009			2008
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(86,309	)	$	(44,002	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Unrealized loss on the fair value of derivatives	2,699			67,309
Loss on property	—			34
Deferred income taxes	—			(25,092		)
Depletion, depreciation, amortization and accretion	17,628			48,893
Impairment of oil and natural gas properties	78,254			—
Gain on ARO settlement	—			(9		)
Amortization of deferred loan costs	1,465			478
Bad debt expense	263			90
Share based compensation costs	359			1,636
Changes in assets and liabilities:
Decrease (increase) in accounts receivable, trade	4,581			(1,508		)
Decrease in accounts receivable, joint interest owners	3,934			7,381
Increase in other assets	(232		)	(355		)
Decrease in accounts payable, trade	(1,395		)	(4,533		)
Increase (decrease) in accrued liabilities	(831		)	3,505
Decrease in other liabilities	(12		)	—
Decrease in accrued interest payable	(557		)	(387		)

Net cash provided by operating activities	19,847			53,440

CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property and equipment additions	(9,232		)	(36,646		)
Decrease in drilling advances	1,275			708
Proceeds from the sale of oil and natural gas properties	328			18,172
Overhedge derivative settlements	—			(6,249		)

Net cash used in investing activities	(7,629		)	(24,015		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of debt	(5,000		)	(20,000		)
Preferred stock dividends paid	—			(4,133		)

Net cash used in financing activities	(5,000		)	(24,133		)

NET INCREASE IN CASH AND CASH EQUIVALENTS	7,218			5,292

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	8,475			7,163

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	15,693		$	12,455

See accompanying notes to consolidated financial statements.

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EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

							Additional						Total
	Preferred Stock			Common Stock			Paid-In			Retained			Stockholders’
	Shares	Amount		Shares	Amount		Capital			Deficit			Equity
	(in thousands)
BALANCE, DECEMBER 31, 2008	2,875	$	29	28,833	$	288	$	423,951		$	(326,780	)	$	97,488

Issuance of common stock	—	—		34	1		(1		)	—			—

Share-based compensation costs	—	—		—	—		359			—			359

Net loss	—	—		—	—		—			(86,309		)	(86,309		)

BALANCE, JUNE 30, 2009	2,875	$	29	28,867	$	289	$	424,309		$	(413,089	)	$	11,538

See accompanying notes to consolidated financial statements.

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EDGE PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS FOR PRESENTATION

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, except for the impairment of the Company’s oil and natural gas properties, as discussed below. 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, 2008.

2. RECENT DEVELOPMENTS

Financial and Strategic Alternatives Process - In late 2007, the Company announced the hiring of a financial advisor to assist its Board of Directors with an assessment of strategic alternatives. The credit crisis and related turmoil in the global financial system and economic recession in the U.S. during the fourth quarter of 2008, along with declines in commodity prices and our stock prices, created a challenging environment for the successful completion of our proposed merger with Chaparral Energy, Inc. (“Chaparral”), a privately held company. On December 17, 2008, the Company announced the termination of the Chaparral merger agreement after both the Company and Chaparral determined it was highly unlikely that the conditions to the closing of the proposed merger would be satisfied or that Chaparral would be able to obtain sufficient debt and equity financing to allow them to complete the proposed merger and operate as a combined company, particularly in light of the challenging environment in the financial markets and the energy industry. The Company has continued undertaking the evaluation and assessment of various financial and strategic alternatives in the first half of 2009 in order to address its liquidity issues and the impending maturity of the Company’s Revolving Facility (defined in Note 4) on August 31, 2009. In connection with this process, the Company also retained a new investment banking firm early in 2009 to assist further in the evaluation of our financial and strategic alternatives. The Company continues to pursue and review its financial and strategic alternatives as it seeks to resolve the many challenges it currently faces.

On July 31, 2009 the Company entered into Amendment No. 8 (“Amendment No. 8”) which changed the maturity date of the Company’s Revolving Facility from July 31, 2009 to August 31, 2009.

Going Concern — In addition to the Deficiency under our Revolving Facility created by the January borrowing base redetermination (see discussion in Note 4), the capital expenditures required to maintain and/or grow production and reserves are substantial. Prices for oil and natural gas declined materially during the fourth quarter of 2008, and natural gas prices continued to decline during the first half of 2009. A continued or extended decline in oil or natural gas prices will have a material adverse effect on the Company’s financial position, results of operations, cash flows and access to capital and on the quantities of oil and natural gas reserves that the Company can economically produce. The Company’s stock price has significantly declined over the past year which also makes it more difficult to obtain equity financing on acceptable terms to address the Company’s liquidity issues. In addition, the Company is reporting negative working capital at June 30, 2009 and continued to report net losses in the three and six months ended June 30, 2009, following three consecutive years of net losses. Therefore, there is substantial doubt as to the Company’s ability to continue as a going concern for a period longer than the next twelve months. Additionally, our independent auditors included an explanatory paragraph in their report on our consolidated financial statements in our Form 10-K for the year

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ended December 31, 2008 that raises substantial doubt about our ability to continue as a going concern. The Company’s ability to continue as a going concern is dependent upon the success of its financial and strategic alternatives process, which may include the sale of some or all of our assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company. Until the possible completion of the financial and strategic alternatives process, the Company’s future remains uncertain and there can be no assurance that its efforts in this regard will be successful.

The accompanying consolidated financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which implies that the Company will continue to meet its obligations and continue its operations for the next twelve months. Realization values may be substantially different from carrying values as shown, and these consolidated financial statements do not include any adjustments relating to the recoverability or classification of recorded asset amounts or the amount and classification of liabilities that might be necessary as a result of this uncertainty.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the succes sful-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 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, which constitutes one cost center. The Company also capitalizes a portion of interest expense on borrowed funds.

In the measurement of impairment of oil and natural gas properties, the successful-efforts method 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 the “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, prior impairments, and related tax effects) 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. A ceiling test impairment could result in a significant loss for a reporting period; however, future depletion expense would be correspondingly reduced. Impairment of oil and natural gas properties is assessed on a quarterly basis in conjunction with the Company’s quarterly and annual SEC filings. The Company recorded a net non-cash ceiling test impairment of $78.3 million during the quarter ended March 31, 2009 as a result of further declines in commodity prices since December 31, 2008. No ceiling test impairment was required during the quarters ended June 30, 2009 or 2008.

In accordance with SEC Staff Accounting Bulletin (“SAB”) No. 103, Update of Codification of Staff Accounting Bulletins , derivative instruments qualifying as cash flow hedges are to be included in the computation of limitation on capitalized costs. Since January 1, 2006, the Company has not applied cash flow hedge accounting to any derivative contracts (see Note 10), therefore the ceiling tests at June 30, 2009 and 2008 were not impacted by the value of our derivatives.

Oil and natural gas properties are amortized based on a unit-of-production method using estimates of proved reserve quantities. Oil and natural gas liquids (“NGL”) are converted to a gas equivalent basis (“Mcfe”) at the rate of one barrel equals six Mcf. In accordance with SAB No. 106, Interaction of Statement 143 and the

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Full Cost Rules, the amortizable base includes estimated future development and dismantlement costs, and restoration and abandonment costs, net of estimated salvage values. 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, 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. Costs excluded from amortization related to unproved properties were $23.0 million and $16.4 million at June 30, 2009 and December 31, 2008, respectively.

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.

Financial Instruments — The Company adopted FASB FSP FAS 107-1 and Accounting Principles Bulletin (“APB”) No. 28-1, Interim Disclosures about Fair Value of Financial Instruments, effective April 1, 2009. FSP FAS 107-1 and APB No. 28-1 requires disclosures about fair value of financial instruments for publicly traded companies for both interim and annual periods. Historically, these disclosures were only required annually. The interim disclosures are intended to provide financial statement users with more timely and transparent information about the effects of current market conditions on an entity’s financial instruments that are not otherwise reported at fair value. The Company’s financial instruments consist of cash, receivables, payables, debt and oil and natural gas commodity derivatives. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of these items. Derivative instruments are reflected at fair value based on quotes obtained from the Company’s counterparties (see Note 10). The carrying amount of the Company’s debt as of December 31, 2008 approximated fair value because the interest rates were variable and reflective of market rates, but as of June 30, 2009 the Company believes it is not practicable to estimate the fair value of its outstanding debt in light of the impending maturity on August 31, 2009 that the Company is currently seeking to address. The carrying amount of the Company’s debt as of June 30, 2009 was $234 million and the interest rate applied at June 30, 2009 was 5.75%. As provided by Amendment No. 8, the maturity date of the outstanding debt is August 31, 2009.

Accounts Receivable and Allowance for Doubtful Accounts - The Company routinely assesses the recoverability of all material trade and other receivables to determine its ability to collect the receivables in full. Accounts Receivable, Joint Interest Owners included an allowance for doubtful accounts of approximately $175,700 and $15,300 at June 30, 2009 and December 31, 2008, respectively. Accounts Receivable, Trade included an allowance for doubtful accounts of approximately $167,500 and $64,500 at June 30, 2009 and December 31, 2008, respectively.

Inventories — Inventories consist principally of tubular goods and production equipment for wells and facilities. They are stated at the lower of weighted-average cost or market and are included in Other Current Assets on the consolidated balance sheet.

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. Under SFAS No. 143, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural 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. The changes to the Asset Retirement Obligations (“ARO”) for oil and natural gas properties and related equipment during the six months ended June 30, 2009 and 2008 are as follows:

	Six Months Ended June 30,
	2009			2008
	(in thousands)
ARO, Beginning of Period	$	6,558		$	6,634
Liabilities incurred in the current period	11			490
Liabilities settled/sold in the current period	(12		)	(1,143		)
Accretion expense	192			191
Revisions	(13		)	151
ARO, End of Period	$	6,736		$	6,323

Current Portion	$	555		$	431
Long-Term Portion	$	6,181		$	5,892

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During the six months ended June 30, 2009, ARO liabilities were recorded for two new obligations and liabilities settled include three properties. Revisions resulted from a change in working interest on a property located in Texas.

Revenue Recognition and Gas Balancing - The Company recognizes oil and natural gas revenue from its interests in producing wells as oil and natural gas is produced and sold from those wells. Oil and natural gas sold by the Company is typically not significantly different from the Company’s share of production. But gas imbalances can occur when sales are more or less than the Company’s entitled ownership percentage of total gas production. Gas imbalances may be accounted for under either the (1) entitlements method, whereby revenue is recorded on the Company’s interest in the gas production actually sold or (2) sales method, whereby revenue is recorded on the basis of total gas actually sold by the Company. The Company uses the sales method of accounting for gas balancing and an asset or a liability is recognized to the extent that there is a material imbalance in excess of the remaining gas reserves on the underlying properties. As of June 30, 2009 and December 31, 2008, our gas production was materially in balance, i.e. our cumulative portion of gas production taken and sold from wells in which we have an interest was not materially different from our entitled interest in gas production from those wells.

Share-Based Compensation — The Company accounts for share-based compensation in accordance with the provisions of SFAS No. 123R, Share-Based Payment, which requires that the compensation cost relating to share-based payment transactions be recognized in financial statements. Share-based compensation for the six months ended June 30, 2009 was approximately $0.4 million, of which approximately $0.2 million was included in general and administrative expenses (“G&A”) and approximately $0.2 million was capitalized to oil and natural gas properties. Share-based compensation for the six months ended June 30, 2008 was approximately $1.3 million, of which $1.1 million was included in G&A and $0.2 million was capitalized to oil and natural gas properties.

During the six months ended June 30, 2009, no restricted stock units (“RSUs”) were granted. At June 30, 2009, there were 211,504 RSUs outstanding, all of which were classified as equity instruments. No options were granted during the six months ended June 30, 2009, and at period end, there were 381,000 vested unexercised options outstanding.

Income Taxes - Effective January 1, 2007, the Company adopted FASB Interpretation No. 48 Accounting for Uncertainty in Income Taxes (an interpretation of FASB Statement No. 109) (“FIN 48”). This interpretation clarified the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on de-recognitions, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company also adopted FASB Staff Position (“FSP”) FIN 48-1, Definition of Settlement in FASB Interpretation No. 48 as of January 1, 2007. FSP FIN 48-1 provides that a company’s tax position will be considered settled if the taxing authority has completed its examination, the company does not plan to appeal, and it is remote that the taxing authority would reexamine the tax position in the future (see Note 8).

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Other Comprehensive Income (Loss) — For the periods presented, total comprehensive loss consisted of:

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in thousands)
Net Loss	$	(9,369	)	$	(27,823	)	$	(86,309	)	$	(44,002	)
Preferred Stock Dividends	—			(2,067		)	—			(4,133		)

Net Loss to Common Stockholders	(9,369		)	(29,890		)	(86,309		)	(48,135		)


Other Comprehensive Income (Loss), Net of Tax	—			—			—			—
Other Comprehensive Loss	$	(9,369	)	$	(29,890	)	$	(86,309	)	$	(48,135	)

Fair Value Measurements — Effective January 1, 2008, the Company partially adopted SFAS No. 157, Fair Value Measurements, which provides a common definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements, but does not require any new fair value measurements. On January 1, 2009 the Company adopted SFAS No. 157 for the non-financial assets and non-financial liabilities that were delayed in adoption by FSP FAS 157-2, Effective Date of FASB Statement No. 157 . Accordingly, the Company has now applied the provisions of SFAS No. 157 to its AROs. The adoption of SFAS No. 157 had no impact on the Company’s financial statements, but it did result in additional required disclosures as set forth in Note 11.

Subsequent Events — The Company adopted SFAS No. 165, Subsequent Events, effective April 1, 2009. SFAS No. 165 does not change the Company’s accounting policy for subsequent events, but instead incorporates existing accounting and disclosure requirements related to subsequent events into generally accepted accounting principles in the United States of America (“GAAP”). SFAS No. 165 defines subsequent events as either recognized subsequent events, those that provide additional evidence about conditions at the balance sheet date, or nonrecognized subsequent events, those that provide evidence about conditions that arose after the balance sheet date. Recognized subsequent events are recorded in the financial statements for the period being presented, while nonrecognized subsequent events are not. Both types of subsequent events require disclosure in the consolidated financial statements if those financial statements would otherwise be misleading. SFAS No. 165 requires the Company to disclose the date through which subsequent events have been evaluated. The adoption of SFAS No. 165 had no impact on the financial statements of the Company. The Company has evaluated subsequent events through August 6, 2009, the filing date of this Quarterly Report on Form 10-Q (see Note 12).

Recent Accounting Pronouncements Not Yet Adopted — In December 2008, the SEC issued the final rule, “Modernization of Oil and Gas Reporting ,” which adopts revisions to the SEC’s oil and natural gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. Early adoption of the new rules is prohibited. The new rules are intended to provide investors with a more meaningful and comprehensive understanding of oil and natural gas reserves to help investors evaluate their investments in oil and natural gas companies. The new rules are also designed to modernize the oil and natural gas disclosure requirements to align them with current practices and changes in technology. The new rules include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves and permitting disclosure of probable and possible reserves. The Company is currently evaluating the potential impact of these rules. The SEC is discussing the rules with the FASB staff to align FASB accounting standards with the new SEC rules. These discussions may delay the required compliance date. Absent any change in the effective date, the Company will begin complying with the disclosure requirements in our annual report on Form 10-K for the year ended December 31, 2009.

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disclosures about an enterprise’s involvement with a variable interest entity. This statement is effective for the beginning of the first annual reporting period beginning after November 15, 2009. The Company does not currently expect the adoption of SFAS No. 167 to impact its consolidated financial statements.

On June 3, 2009, the FASB approved the FASB Accounting Standards Codification™ (“Codification”) as the single source of GAAP. On June 29, 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards Codification TM and the Hierarchy of Generally Accepted Accounting Principles . SFAS No. 168 establishes the Codification to become the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. Codification supersedes all existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification becomes non-authoritative. Following SFAS No. 168, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to: (a) update the Codification; (b) provide background information about the guidance; and (c) provide the bases for conclusions on the change(s) in the Codification. The content of the Codification carries the same level of authority. The GAAP hierarchy will be modified to include only two levels of GAAP: authoritative and non-authoritative. SFAS No. 168 and the Codification are effective for financial statements issued for interim and annual periods ending after September 15, 2009, which means that a calendar year-end public entity should follow the guidelines in the Codification beginning with its third quarter starting on July 1, 2009. The Company adopted Codification on July 1, 2009 which will provide for changes in disclosures on its Quarterly Report on Form 10-Q for the period ended September 30, 2009 but no impact to its financial position, results of operations or cash flows.

4. DEBT

On January 30, 2007, the Company entered into a Fourth Amended and Restated Credit Agreement (as amended, the “Revolving Facility”) for a new revolving credit facility with Union Bank of California (“UBOC”), as administrative agent and issuing lender, and the other lenders party thereto (together with UBOC, the “Lenders”). Pursuant to the Revolving Facility, UBOC acts as the administrative agent for a senior first lien secured borrowing base revolving credit facility in favor of the Company and certain of its wholly-owned subsidiaries in an amount equal to $750 million, of which $320 million was available under the borrowing base at the time of closing (see below for discussion of current availability). The Revolving Facility has a letter of credit sub-limit of $20 million. The Revolving Facility’s original maturity was scheduled for January 31, 2011.

At June 30, 2009, borrowings under the Revolving Facility bore interest at Prime plus a margin of 2.5% which equated to an interest rate applied to the Company’s outstanding borrowings of 5.75%. As of June 30, 2009, $234 million in total borrowings were outstanding under the Revolving Facility.

As a result of the redetermination process of the borrowing base by the Lenders under the Revolving Facility, which was completed in January 2009, the Lenders established a new borrowing base under the Revolving Facility of $125 million, resulting in a $114 million deficiency (the “Deficiency”). The reduction to our borrowing base was primarily the result of the sale of certain non-core assets during the first quarter of 2008 and the reduction of total proved reserves as reported in the year-end reserve reports of the Company’s independent reserve engineers.

Pursuant to the terms of the Revolving Facility, the Company initially elected to prepay the Deficiency in six equal monthly installments, with the first $19 million installment being due on February 9, 2009. The Company has entered into the following consents and amendments (collectively, the “Amendments”) with its Lenders in recent months as a result of the ongoing financial and strategic alternatives process:

· On February 9, 2009, the Company entered into a Consent and Agreement (the “February Consent”) among the Company and the Lenders under the Revolving Facility deferring the payment date of the first $19 million installment until March 10, 2009, and extending the due date for each subsequent installment by one month with the last of the six installment payments to be due on August 10, 2009. In connection with the February Consent, the Company agreed to prepay $5.0 million of the Company’s outstanding advances under the Revolving Facility, in two equal

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installments. The first $2.5 million prepayment was paid on February 9, 2009 and the second $2.5 million prepayment was paid on February 23, 2009, with each of these prepayments applied on a pro rata basis to reduce the six remaining $19 million deficiency payments.

· On March 10, 2009, the Company entered into a Consent and Agreement (the “March Consent”) with the Lenders under the Revolving Facility, which provided, among other things, for the extension of the due date for the first installment to repay the Deficiency from March 10, 2009 to March 17, 2009. Notwithstanding such extension, the Company agreed with the Lenders that each of the other five equal installment payments required to eliminate the Deficiency would be due and payable as provided for in the February Consent.

· On March 16, 2009, the Company entered into Consent and Amendment No. 4 (the “Amended Consent”) which provided, among other things, (1) that the Company would make a $25 million payment on May 31, 2009 with all remaining principal, fees and interest amounts under the Revolving Facility to be due and payable on June 30, 2009, (2) that it will be an event of default (i) if the Company failed to have executed and delivered on or before May 15, 2009 at least one of the following (a) a commitment letter from a lender or group of lenders reasonably satisfactory to the Lenders providing for the provision by such lender or group of lenders of a credit facility in an amount sufficient to repay all of the Company’s obligations under the Revolving Facility on or before June 30, 2009, (b) a merger agreement or similar agreement involving the Company as part of a transaction that results in the repayment of the Company’s obligations under the Revolving Facility on or before June 30, 2009, and (c) a purchase and sale agreement with a buyer or group of buyers reasonably acceptable to the Company’s Lenders providing for a sale transaction by us that results in the repayment of all of the Company’s obligations under the Revolving Facility on or before June 30, 2009, or (ii) if the Company is in default under or its hedging arrangements have been terminated or cease to be effective without the prior written consent of its Lenders, (3) that the Company’s advances under the Revolving Facility would bear interest at a rate equal to the greater of (a) the reference rate publicly announced by Union Bank of California, N.A. for such day, (b) the Federal Funds Rate in effect on such day plus 0.50% and (c) a rate determined by the Administrative Agent to be the Daily One-Month LIBOR (as defined in the Revolving Facility), in each case plus 2.5% or, during the continuation of an event of default, plus 4.5% (resulting in an effective interest rate of approximately 5.75%), (4) for severe limitations on the making of capital expenditures and certain investments, and (5) for the elimination of the current ratio, leverage ratio and interest coverage ratio covenant requirements. The Amended Consent also eliminated the six $19 million deficiency payments which were contemplated by the February Consent and the March Consent.

· On May 15, 2009, the Company entered into Amendment No. 5 (“Amendment No. 5”) which provided for, among other things, (1) the elimination of the provision providing that it would be an event of default if the Company failed to have executed and delivered on or before May 15, 2009 at least one of the following (a) a commitment letter from a lender or group of lenders reasonably satisfactory to the lenders providing for the provision by such lender or group of lenders of a credit facility in an amount sufficient to repay all of the Company’s obligations under the Revolving Facility on or before June 30, 2009, (b) a merger agreement or similar agreement involving the Company as part of a transaction that resulted in the repayment of the Company’s obligations under the Revolving Facility on or before June 30, 2009, and (c) a purchase and sale agreement with a buyer or group of buyers reasonably acceptable to the Lenders providing for a sale transaction by the Company that resulted in the repayment of all of the Company’s obligations under the Revolving Facility on or before June 30, 2009 and (2) the elimination of certain reporting requirements relating to certificates to be provided by the Company’s auditors and responsible officers.

· On May 29, 2009, the Company entered into Amendment No. 6 (“Amendment No. 6”) which eliminated the May 31, 2009 payment obligation and provided that the related $25 million payment for outstanding advances as well as any unpaid interest thereon and all remaining principal, fees and interests amounts under the Revolving Facility would be due on June 30, 2009.

· On June 30, 2009, the Company entered into Amendment No. 7 (“Amendment No. 7”) which provided for, among other things, (1) changing the maturity date of the Revolving Facility from June 30, 2009 to July 31, 2009, (2) the Company’s agreement to make a prepayment of interest of $1,142,753.42 million representing the amount anticipated to be owing in respect of the interest

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payment due and payable on July 31, 2009 and (3) the Company’s agreement to make a prepayment of the advances under the Revolving Facility in the amount of $7.5 million with such prepayment to be made on or before July 10, 2009. The Company paid the July interest of approximately $1.1 million on July 1, 2009 and also paid $7.5 million on July 10, 2009.

· On July 31, 2009 the Company entered into Amendment No. 8 (“Amendment No. 8”) which changed the maturity date of the Company’s Revolving Facility from July 31, 2009 to August 31, 2009.

If the Company breaches any of the provisions of the Amended Consent or Revolving Facility, as amended, the Lenders thereto will be entitled to declare an event of default, at which point the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, would become immediately due and payable. In any event, the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to the Lenders, will be payable on August 31, 2009 unless earlier paid or a further extension with respect to payment is negotiated with the Lenders. The Lenders may take action to enforce their rights with respect to the outstanding obligations under the Revolving Facility. Because substantially all of the Company’s assets are pledged as collateral under the Revolving Facility, if the Lenders declare an event of default, they would be entitled to foreclose on and take possession of the Company’s assets. In such an event, the Company may be forced to liquidate or to otherwise seek protection under Chapter 11 of the U.S. Bankruptcy Code. Such action in itself would constitute an event of default under the terms of the Revolving Facility. These matters, as well as the other risk factors related to the Company’s liquidity and financial position raise substantial doubt as to our ability to continue as a going concern (see Note 2) . With respect to the Company’s compliance with the Amended Consent, there can be no assurance that the Company will be able to further negotiate the terms of the Amended Consent or negotiate a further restructuring of the related indebtedness or that it will be able to either make any required payments when they become due. Moreover, there can be no assurance that the Company will be successful in its efforts to comply with the terms of the Amended Consent, including its ongoing efforts to evaluate and assess our various financial and strategic alternatives (which may include the sale of some or all of our assets, a merger or other business combination involving the Company, or the restructuring or recapitalization of the Company). If such efforts are not successful, the Company may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code, which would constitute an event of default under the Revolving Facility. See Item 1A. RISK FACTORS .

The Company’s obligations under the Revolving Facility are secured by substantially all of the Company’s assets. The Revolving 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 Revolving Facility restricts dividends on common stock and certain distributions of cash or properties and certain liens but no longer contains any financial covenants as a result of the Amended Consent.

The Revolving Facility includes certain other covenants and events of default that are customary for similar facilities. It is an event of default under the Revolving Facility if the Company undergoes a change of control. “Change of control,” as defined in the Revolving Facility, means any of the following events: (a) any “person” or “group” (within the meaning of Section 13(d) or 14(d) of the Exchange Act) has become, directly or indirectly, the “beneficial owner” (as defined in Rules 13d-3 and 13d-5 under the Exchange Act, except that a person shall be deemed to have “beneficial ownership” of all such shares that any such person has the right to acquire, whether such right is exercisable immediately or only after the passage of time, by way of merger, consolidation or otherwise), of a majority or more of the common stock of the Company on a fully-diluted basis, after giving effect to the conversion and exercise of all outstanding warrants, options and other securities of the Company (whether or not such securities are then currently convertible or exercisable), (b) during any period of two consecutive calendar quarters, individuals who at the beginning of such period were members of the Company’s Board of Directors cease for any reason to constitute a majority of the directors then in office unless (i) such new directors were elected by a majority of the directors of the Company who constituted the Board of Directors at the beginning of such period (or by directors so elected) or (ii) the reason for such directors failing to constitute a majority is a result of retirement by directors due to age, death or disability, or (c) the Company ceases to own directly or indirectly all of the equity interests of each of its subsidiaries.

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5. SHELF REGISTRATION STATEMENT

In the third quarter 2007, the SEC declared effective the Company’s registration statement filed with the SEC that registered securities of up to $500 million of any combination of debt securities, preferred stock, common stock, warrants for debt securities or equity securities of the Company and guarantees of debt securities by the Company’s subsidiaries. Net proceeds, terms and pricing of the offering of securities issued under the shelf registration statement will be determined at the time of the offerings. The shelf registration statement does not provide assurance that the Company will or could sell any such securities. The Company’s ability to utilize the 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 the Company’s securities at prices acceptable to the Company. As of August 4, 2009, the Company had $500 million available under its shelf registration statement. However, because the aggregate market value of the Company’s outstanding common stock is less than $75 million, the type and amount of any securities offering under the registration statement may be limited.

6. PREFERRED STOCK

In January 2007, 2,875,000 shares of its 5.75% Series A cumulative convertible perpetual preferred stock (“Convertible Preferred Stock”) were issued in a public offering.

Dividends . The Convertible Preferred Stock accumulates dividends at a rate of $2.875 for each share of Convertible Preferred Stock per year. Dividends are cumulative from the date of first issuance and, to the extent payment of dividends is not prohibited by the Company’s debt agreements, assets are legally available to pay dividends and the Board of Directors or an authorized committee of the board declares a dividend payable, the Company will pay dividends in cash, every quarter. The first payment was made on April 15, 2007 and the Company continued to make quarterly dividends payments through October 15, 2008. The Board has not declared a dividend since the third quarter of 2008 due to the Company’s current reduced liquidity. Cumulative dividends in arrears at June 30, 2009 amounted to approximately $5.9 million.

No dividends or other distributions (other than a dividend payable solely in shares of a like or junior ranking) may be paid or set apart for payment upon any shares ranking equally with the Convertible Preferred Stock (“parity shares”) or shares ranking junior to the Convertible Preferred Stock (“junior shares”), nor may any parity shares or junior shares be redeemed or acquired for any consideration by the Company (except by conversion into or exchange for shares of a like or junior ranking) unless all accumulated and unpaid dividends have been paid or funds therefor have been set apart on the Convertible Preferred Stock and any parity shares.

Liquidation preference . In the event of the Company’s voluntary or involuntary liquidation, winding-up or dissolution, each holder of Convertible Preferred Stock will be entitled to receive and to be paid out of the Company’s assets available for distribution to our stockholders, before any payment or distribution is made to holders of junior stock (including common stock), but after any distribution on any of our indebtedness or senior stock, a liquidation preference in the amount of $50.00 per share of the Convertible Preferred Stock, plus accumulated and unpaid dividends on the shares to the date fixed for liquidation, winding-up or dissolution.

Ranking . Our Convertible Preferred Stock ranks:

· senior to all of the shares of common stock and to all of the Company’s other capital stock issued in the future unless the terms of such capital stock expressly provide that it ranks senior to, or on a parity with, shares of the Convertible Preferred Stock;

· on a parity with all of the Company’s other capital stock issued in the future, the terms of which expressly provide that it will rank on a parity with the shares of the Convertible Preferred Stock; and

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· junior to all of the Company’s existing and future debt obligations and to all shares of its capital stock issued in the future, the terms of which expressly provide that such shares will rank senior to the shares of the Convertible Preferred Stock.

Mandatory conversion . On or after January 20, 2010, the Company may, at its option, cause shares of its Convertible Preferred Stock to be automatically converted to shares of common stock of the Company at the applicable conversion rate, but only if the closing sale price of its common stock for 20 trading days within a period of 30 consecutive trading days ending on the trading day immediately preceding the date the Company gives the conversion notice equals or exceeds 130% of the conversion price in effect on each such trading day.

Optional redemption . If fewer than 15% of the shares of Convertible Preferred Stock issued in the Convertible Preferred Stock offering (including any additional shares issued pursuant to the underwriters’ over-allotment option) are outstanding, the Company may, at any time on or after January 20, 2010, at its option, redeem for cash all such Convertible Preferred Stock at a redemption price equal to the liquidation preference of $50.00 plus any accrued and unpaid dividends, if any, on a share of Convertible Preferred Stock to, but excluding, the redemption date, for each share of Convertible Preferred Stock.

Conversion rights . Each share of Convertible Preferred Stock may be converted at any time, at the option of the holder, into approximately 3.0193 shares of the Company’s common stock (which is based on an initial conversion price of $16.56 per share of common stock, subject to adjustment) plus cash in lieu of fractional shares, subject to the Company’s right to settle all or a portion of any such conversion in cash or shares of its common stock. If the Company elects to settle all or any portion of its conversion obligation in cash, the conversion value and the number of shares of its common stock the Company will deliver upon conversion (if any) will be based upon a 20 trading day averaging period.

Upon any conversion, the holder will not receive any cash payment representing accumulated and unpaid dividends on the Convertible Preferred Stock, whether or not in arrears, except in limited circumstances. The conversion rate is equal to $50.00 divided by the conversion price at the time. The conversion price is subject to adjustment upon the occurrence of certain events. The conversion price on the conversion date and the number of shares of the Company’s common stock, as applicable, to be delivered upon conversion may be adjusted if certain events occur.

Purchase upon fundamental change . If the Company becomes subject to a fundamental change (as defined below), each holder of shares of Convertible Preferred Stock will have the right to require the Company to purchase any or all of its shares at a purchase price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends, to the date of the purchase. The Company will have the option to pay the purchase price in cash, shares of common stock or a combination of cash and shares. The Company’s ability to purchase all or a portion of the Convertible Preferred Stock for cash is subject to its obligation to repay or repurchase any outstanding debt required to be repaid or repurchased in connection with a fundamental change and to any contractual restrictions then contained in our debt.

Conversion in connection with a fundamental change . If a holder elects to convert its shares of the Convertible Preferred Stock in connection with certain fundamental changes, the Company will in certain circumstances increase the conversion rate for such Convertible Preferred Stock. Upon a conversion in connection with a fundamental change, the holder will be entitled to receive a cash payment for all accumulated and unpaid dividends.

A “fundamental change” will be deemed to have occurred upon the occurrence of any of the following:

1. a “person” or “group” subject to specified exceptions, discloses that the person or group has become the direct or indirect ultimate “beneficial owner” of the Company’s common equity representing more than 50% of the voting power of its common equity other than a filing with a disclosure relating to a transaction which complies with the proviso in subsection 2 below;

2. consummation of any share exchange, consolidation or merger of the Company pursuant to which its common stock will be converted into cash, securities or other property or any sale, lease or other transfer in one transaction or a series of transactions of all or substantially all of the consolidated assets

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of the Company and its subsidiaries, taken as a whole, to any person other than one of its subsidiaries; provided, however, that a transaction where the holders of more than 50% of all classes of its common equity immediately prior to the transaction own, directly or indirectly, more than 50% of all classes of common equity of the continuing or surviving corporation or transferee immediately after the event shall not be a fundamental change;

3. the Company is liquidated or dissolved or holders of its capital stock approve any plan or proposal for its liquidation or dissolution; or

4. the Company’s common stock is neither listed on a national securities exchange nor listed nor approved for quotation on an over-the-counter market in the United States.

However, a fundamental change will not be deemed to have occurred in the case of a share exchange, merger or consolidation, or in an exchange offer having the result described in subsection 1 above, if 90% or more of the consideration in the aggregate paid for common stock (and excluding cash payments for fractional shares and cash payments pursuant to dissenters’ appraisal rights) in the share exchange, merger or consolidation or exchange offer consists of common stock of a United States company traded on a national securities exchange (or which will be so traded or quoted when issued or exchanged in connection with such transaction).

Voting rights . If the Company fails to pay dividends for six quarterly dividend periods (whether or not consecutive) or if the company fails to pay the purchase price on the purchase date for the Convertible Preferred Stock following a fundamental change, holders of the Convertible Preferred Stock will have voting rights to elect two directors to the board.

In addition, the Company may generally not, without the approval of the holders of at least 66 2/3% of the shares of the Convertible Preferred Stock then outstanding:

· amend the restated certificate of incorporation, as amended, by merger or otherwise, if the amendment would alter or change the powers, preferences, privileges or rights of the holders of shares of the Convertible Preferred Stock so as to adversely affect them;

· issue, authorize or increase the authorized amount of, or issue or authorize any obligation or security convertible into or evidencing a right to purchase, any senior stock; or

· reclassify any of its authorized stock into any senior stock of any class, or any obligation or security convertible into or evidencing a right to purchase any senior stock.

7. EARNINGS (LOSS) PER SHARE

The Company accounts for earnings (loss) 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 statement of operations. Basic EPS amounts are calculated using the weighted average number of common shares outstanding during each period. Diluted EPS assumes the exercise of all stock options, warrants and convertible securities having exercise prices less than the average market price of the common stock during the periods, using the treasury stock method. When a loss from continuing operations exists, as in the periods presented, potential common shares are excluded in the computation of diluted EPS because their inclusion would result in an anti-dilutive effect on per share amounts.

Diluted EPS also includes the effect of convertible securities by application of the “if-converted” method. Under this method, if an entity has convertible preferred stock outstanding, the preferred dividends applicable to the convertible preferred stock are added back to the numerator. The convertible preferred stock is assumed to have been converted at the beginning of the period (or at time of issuance, if later) and the resulting common shares are included in the denominator of the EPS calculation. In applying the if-converted method, conversion is not assumed for purposes of computing diluted EPS if the effect would be anti-dilutive. During 2009 and

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2008, conversion of the 5.75% Series A cumulative convertible preferred stock is not assumed because the effect would be anti-dilutive. The following tables present the computations of EPS for the periods indicated.

	Three Months Ended June 30, 2009							Three Months Ended June 30, 2008
	Loss (Numerator)			Shares (Denominator)(1)	Per Share Amount			Loss (Numerator)			Shares (Denominator)	Per Share Amount
	(in thousands, except per share amounts)
Net loss	$	(9,369	)					$	(27,823	)
Less: Preferred stock dividends paid	—							(2,067		)
Less: Preferred stock dividends in arrears	(2,067		)					—

Basic EPS
Net loss to common stockholders	(11,436		)	28,867	$	(0.40	)	(29,890		)	28,652	$	(1.04	)
Effect of dilutive securities:
Restricted stock units	—			—	—			—			—	—
Common stock options	—			—	—			—			—	—
Convertible preferred stock	—			—	—			—			—	—
Diluted EPS
Net loss to common stockholders	$	(11,436	)	28,867	$	(0.40	)	$	(29,890	)	28,652	$	(1.04	)

	Six Months Ended June 30, 2009							Six Months Ended June 30, 2008
	Loss (Numerator)			Shares (Denominator)(1)	Per Share Amount			Loss (Numerator)			Shares (Denominator)(2)	Per Share Amount
	(in thousands, except per share amounts)
Net loss	$	(86,309	)					$	(44,002	)
Less: Preferred stock dividends paid	—							(4,133		)
Less: Preferred stock dividends in arrears	(4,133		)					—

Basic EPS
Net loss to common stockholders	(90,442		)	28,854	$	(3.13	)	(48,135		)	28,609	$	(1.68	)
Effect of dilutive securities:
Restricted stock units	—			—	—			—			—	—
Common stock options	—			—	—			—			—	—
Convertible preferred stock	—			—	—			—			—	—
Diluted EPS
Net loss to common stockholders	$	(90,442	)	28,854	$	(3.13	)	$	(48,135	)	28,609	$	(1.68	)

(1) In the calculation of diluted EPS for the three and six months ended June 30, 2009, the 8.7 million shares of common stock resulting from an assumed conversion of the Company’s Convertible Preferred Stock is excluded because the conversion would be anti-dilutive.

(2) In the calculation of diluted EPS for the three and six months ended June 30, 2008, the 8.7 million shares of common stock resulting from an assumed conversion of the Company’s Convertible Preferred Stock is excluded because the conversion would be anti-dilutive. Additionally, for the three and six months ended June 30, 2008, 63,839 and 65,109, respectively, equivalent shares of the Company’s restricted stock units and common stock options were excluded because the conversion would also be anti-dilutive.

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8. 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.

In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company considers the scheduled reversal of deferred income tax liabilities and projected future taxable income for this determination. The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to the historical evidence, and in light of the current market situation and the uncertainty surrounding the Company’s Revolving Facility, as amended, and related Amended Consent (see Notes 2 and 4), management is not able to determine that it is more likely than not that the deferred tax assets will be realized Therefore, the Company fully provided for additions to its deferred tax asset with a valuation allowance during the period and did not record a tax benefit for the three or six months ended June 30, 2009. The Company established a full valuation allowance and reduced its net deferred tax asset to zero during 2008. The Company will continue to assess the valuation allowance against deferred income tax assets considering all available information obtained in future reporting periods. If the Company achieves profitable operations in the future, it may reverse a portion of the valuation allowance in an amount at least sufficient to eliminate any tax provision in that period. The valuation allowance has no impact on the Company’s net operating loss (“NOL”) position for tax purposes, and if the Company generates taxable income in future periods, it will be able to use its NOLs to offset taxes due at that time.

As of June 30, 2009, the Company had $0.1 million of unrecognized tax benefits related to FIN 48. There were no significant changes to the calculation since December 31, 2008. The Company does not expect the amount of unrecognized tax benefits to materially change in 2009.

9. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION AND 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 is presented below:

Description	Number of Shares Issued	Grant Date Fair Market Value
	(in thousands)
Six Months Ended June 30, 2009:
Shares issued to satisfy restricted stock grants	34	$	622
Six Months Ended June 30, 2008:
Shares issued to satisfy restricted stock grants	52	$	1,074
Shares issued to fund the Company’s matching contribution under the Company’s 401(k) plan	61	$	324

For the six months ended June 30, 2009 and 2008, the non-cash portion of Asset Retirement Costs was approximately $14,400 and $0.5 million, respectively. Preferred stock dividends declared but not yet paid at June 30, 2008 were $2.1 million, of which $1.7 million was accrued at June 30, 2008. There were no dividends declared or accrued at June 30, 2009. A supplemental disclosure of cash flow information is presented below:

	For the Six Months Ended June 30,
	2009		2008
	(in thousands)
Cash paid during the period for:
Interest, net of amounts capitalized	$	5,881	$	6,896

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10. HEDGING AND DERIVATIVE ACTIVITIES

The Company utilizes price-risk management transactions (e.g., swaps, collars and floors) for a portion of its expected oil and natural gas production to seek to reduce exposure from the volatility of oil and natural gas prices and also to achieve a more predictable cash flow. While the use of these arrangements is intended to reduce the Company’s potential exposure to significant commodity price declines, they may limit the Company’s ability to benefit from increases in the price of oil and natural gas. The Company’s arrangements, to the extent it enters into any, are intended to apply to only a portion of its expected production and thereby provide only partial price protection against declines in oil and natural gas prices. None of these instruments are, at the time of their execution, intended to be used for trading or speculative purposes, but a portion of the Company’s 2008 instruments was subsequently deemed as such because of the decrease in the Company’s 2008 production. These price-risk management transactions are generally placed with major financial institutions that the Company believes are financially stable; however, in light of the recent global financial crisis, there can be no assurance of the foregoing. None of the Company’s derivative contracts contain collateral posting requirements; however, the counterparty to the Company’s 2009 positions is a member of the lending group of the Company’s Revolving Facility, and certain events of default under the Company’s Revolving Facility may result in a cross default of derivative instruments with such party. In addition, the Company’s counterparty is entitled to terminate the derivative contracts in the event that the fair market value of the derivative contracts (currently valued at approximately $12.7 million as of June 30, 2009) falls to less than $1.5 million (i.e. the approximate amount that the Company’s counterparty would owe the Company upon termination of the derivative contracts following the decline of the derivative fair market value from the approximate $12.7 million as of June 30, 2009 to less than $1.5 million at any time thereafter). In the event of a termination of the derivative contracts by the Company’s counterparty under these circumstances, there can be no assurance that this counterparty would actually remit the funds owed to the Company as opposed to attempting to apply such funds as an offset to the Company’s indebtedness under the Revolving Facility of which they are a lender. However, to the extent that any decrease in the fair market value of the derivative contracts is driven by higher commodity prices, such rising commodity prices should result in some benefit to the Company’s expected oil and natural gas sales revenue. On an annual 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 reviews the Company’s policies and trades monthly. However, due to the ongoing financial and strategic alternatives process the Company has not entered into any new derivative contracts in recent months and does not expect to for the foreseeable future.

All of these price-risk management transactions are considered derivative instruments and accounted for in accordance with SFAS No. 133 (as amended). These derivative instruments are intended to hedge the Company’s 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 instruments, other than those that meet the normal purchases and sales exception, are recorded on the balance sheet at fair value. The estimated fair value of these contracts is based upon various factors, including closing exchange prices on the NYMEX, over-the-counter quotations, volatility and, in the case of collars and floors, the time value of options. The calculation of the fair value of collars and floors requires the use of an option-pricing model (see Note 11). The cash flows resulting from settlement of derivative transactions which relate to economically hedging the Company’s physical production volumes are classified in operating activities on the statement of cash flows and the cash flows resulting from settlement of derivative transactions considered “overhedged” positions are classified in investing activities on the statement of cash flows. For those derivatives in which mark-to-market accounting treatment is applied, the changes in fair value are not deferred through other comprehensive income (“OCI”) on the balance sheet. Rather they are immediately recorded in total revenue on the statement of operations. For those derivative instrument contracts that are designated and qualify for cash flow hedge accounting, the effective portion of the changes in the fair value of the contracts is recorded in OCI on the balance sheet and the ineffective portion of the changes in the fair value of the contracts is recorded in total revenue on the statement of operations, in either case, as such changes occur. When the hedged production is sold, the realized gains and losses on the contracts are removed from OCI and recorded in total revenue on the statement of operations, which reduces the period to period volatility impacting the statement of operations that may occur throughout the contract term. While the contract is outstanding, the unrealized gain or loss may increase or decrease until

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settlement of the contract depending on the fair value at the measurement dates. The Company evaluates the terms of new contracts entered into to determine whether cash flow hedge accounting treatment or mark-to-market accounting treatment will be applied. The Company has applied mark-to-market accounting treatment to all outstanding contracts since January 1, 2006.

The fair value of outstanding derivative contracts not designated as hedging instruments under SFAS No. 133 (as amended) reflected on the balance sheet was as follows:

Fair Value of Outstanding

Price

Derivative Contracts as of

Transaction

Per

Volumes

Balance Sheet

June 30,

December 31,

Date

Type

Beginning

Ending

Unit

Per Day

Location

2009

2008

(in thousands)

Natural Gas (1):

04/07

Collar

1/1/2009

12/31/2009

$7.75-$10.00

10,000 MMBtu

Derivative Financial Instruments - Current Assets

6,247

6,688

10/07

Collar

1/1/2009

12/31/2009

$7.75-$10.08

10,000 MMBtu

Derivative Financial Instruments - Current Assets

6,248

6,702

Crude Oil (2):

10/07

Collar

1/1/2009

12/31/2009

$70.00-$93.55

300 Bbl

Derivative Financial Instruments - Current Assets

214

2,017

Total derivatives not designated as hedging instruments under SFAS No. 133

12,709

15,407

(1) The Company’s natural gas contracts were entered into on a per MMBtu delivered price basis, using the NYMEX Natural Gas Index. Mark-to-market accounting treatment is applied to these contracts and the change in fair value is reflected in total revenue.

(2) The Company’s crude oil contract was entered into on a per barrel delivered price basis, using the West Texas Intermediate Light Sweet Crude Oil Index. Mark-to-market accounting treatment is applied to this contract and the change in fair value is reflected in total revenue.

The following table reflects the realized and unrealized gains and losses included in total revenue on the statement of operations:

Derivatives Not Designated as Hedging	Location of Gain or	Amount of Gain or (Loss) Recognized in Income on Derivative
Instruments under	(Loss) Recognized in	Three Months Ended June 30,						Six Months Ended June 30,
SFAS No. 133	Income on Derivative	2009			2008			2009			2008
		(in thousands)
Natural gas derivative realized settlements	Gain (loss) on derivatives — Total revenue	$	7,744		$	(6,733	)	$	12,869		$	(6,370	)
Crude oil derivative realized settlements	Gain (loss) on derivatives — Total revenue	284			(7,916		)	1,007			(12,278		)
Natural gas derivative unrealized change in fair value	Gain (loss) on derivatives — Total revenue	(6,744		)	(30,914		)	(896		)	(56,478		)
Crude oil derivative unrealized change in fair value	Gain (loss) on derivatives — Total revenue	(1,175		)	(11,035		)	(1,803		)	(10,831		)
Gain (loss) on derivatives		$	109		$	(56,598	)	$	11,177		$	(85,957	)

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11. FAIR VALUE MEASUREMENTS

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

Valuation Techniques

In accordance with SFAS No. 157, valuation techniques used for assets and liabilities accounted for at fair value are generally categorized into three types:

· Market Approach . Market approach valuation techniques use prices and other relevant information from market transactions involving identical or comparable assets or liabilities.

· Income Approach . Income approach valuation techniques convert future amounts, such as cash flows or earnings, to a single present amount, or a discounted amount. These techniques rely on current market expectations of future amounts.

· Cost Approach . Cost approach valuation techniques are based upon the amount that, at present, would be required to replace the service capacity of an asset, or the current replacement cost. That is, from the perspective of a market participant (seller), the price that would be received for the asset is determined based on the cost to a market participant (buyer) to acquire or construct a substitute asset of comparable utility.

The three approaches described within SFAS No. 157 are consistent with generally accepted valuation methodologies. While all three approaches are not applicable to all assets or liabilities accounted for at fair value, where appropriate and possible, one or more valuation techniques may be used. The selection of the valuation method(s) to apply considers the definition of an exit price and the nature of the asset or liability being valued and significant expertise and judgment is required. For assets and liabilities accounted for at fair value, valuation techniques are generally a combination of the market and income approaches. Accordingly, the Company aims to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

Input Hierarchy

SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value directly related to the amount of subjectivity associated with the inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

· Level 1 — Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

· Level 2 — Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life. Level 2 includes those financial instruments that are valued using models or other valuation methodologies, which consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

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· Level 3 — Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date.

Fair Value on a Recurring Basis

The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2009. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

Fair Value Measurements Using:

Quoted

Significant

Prices in

Other

Significant

Active

Observable

Unobservable

Total Fair

Markets

Inputs

Value

(Level 1)

(Level 2)

(Level 3)

(in thousands)

Assets:

Derivative instruments

12,709

—

12,709

The following table sets forth a reconciliation of changes in the fair value of the Company’s derivative instruments classified as Level 3 in the fair value hierarchy.

	Three Months Ended June 30, 2009					Six Months Ended June 30, 2009
	Assets			Liabilities		Assets			Liabilities
	(in thousands)
Balance as of beginning of period	$	20,627		$	—	$	15,407		$	—
Realized and unrealized losses included in earnings	(15,946		)	—		(16,574		)	—
Realized and unrealized gains included in other comprehensive income	—			—		—			—
Settlements	8,028			—		13,876			—
Transfers in and/or out of Level 3	—			—		—			—
Balance as of June 30, 2009	$	12,709		$	—	$	12,709		$	—

Change in unrealized gains (losses) relating to instruments still held as of June 30, 2009	$	(177	)	$	—	$	5,713		$	—

Gains and losses (realized and unrealized) for Level 3 recurring items are included in total revenue on the Consolidated Statements of Operations. Settlements represent cash settlements of contracts during the period, which are included in total revenue on the Consolidated Statements of Operations.

Transfers in and/or out represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. There were no transfers in or out of Level 3 during the periods presented.

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Fair Value on a Nonrecurring Basis

On January 1, 2009, the Company adopted the provisions of SFAS No. 157 for non-financial assets and liabilities, which were delayed by FSP FAS 157-2. Therefore, the Company adopted the provisions of SFAS No. 157 for its AROs. The Company uses fair value measurements on a nonrecurring basis in its AROs. These liabilities are recorded at fair value initially and assessed for revisions periodically thereafter. The lowest level of significant inputs for fair value measurements for ARO liabilities are Level 3. A reconciliation of the beginning and ending balances of the Company’s ARO is presented in Note 3, in accordance with SFAS No. 143. New assets and liabilities measured at fair value during the six months ended June 30, 2009 include:

			Fair Value Measurements Using:
			Quoted		Significant
			Prices in		Other		Significant
			Active		Observable		Unobservable
	Total Fair		Markets		Inputs		Inputs
	Value		(Level 1)		(Level 2)		(Level 3)
	(in thousands)
Assets:
Asset retirement costs	$	11	$	—	$	—	$	11

Liabilities:
Asset retirement obligations — current	$	—	$	—	$	—	$	—
Asset retirement obligations — long-term	11		—		—		11

12. SUBSEQUENT EVENTS

On July 31, 2009 the Company entered into Amendment No. 8 (“Amendment No. 8”) which changed the maturity date of the Company’s Revolving Facility from July 31, 2009 to August 31, 2009.

13. COMMITMENTS AND CONTINGENCIES

Delivery Commitments — During 2007, the Company executed a gas gathering and compression services agreement with Frontier Midstream, LLC (“Frontier”). Following execution of such agreement, Frontier expedited the installation of the Rose Bud system in White County, Arkansas, including the high and low pressure gathering lines, dehydration, compression and the interconnect with Ozark, in order to accommodate the Company’s desire to be able to deliver natural gas as soon as its wells were completed. At the time of signing the contract, the Company had completed and tested two productive wells in the Moorefield shale. The Rose Bud system was installed, operational and ready to receive the Company’s production in June 2007. The contract minimum commitment to Frontier is 2.7 Bcf over a three-year period for the pipeline interconnect. This line carries a $0.29 per Mcf deficiency rate, for a total commitment for the pipeline of approximately $0.8 million. The Company has delivered approximately $72,700 of this commitment through June 30, 2009. In addition to the pipeline, Frontier also built and installed lateral gathering lines to eight locations. The remaining commitment on these laterals is approximately $1.3 million, for a total potential liability of approximately $2.0 million to be paid by June 2010 if the minimum volumes are not delivered. The Company recorded a long-term liability for the aggregate amount of $2.0 million in the fourth quarter of 2008, which is revised monthly as volumes produced reduce the liability. Although the Company believes there is the potential to develop this area and increase production, it does not currently have sufficient liquidity to ensure that this occurs in the timeframe required by the gas gathering and compression services agreement with Frontier.

During 2008, the Company executed a gas gathering and compression services agreement with Integrys Energy Services (“Integrys”) related to the construction and installation of a pipeline connecting the Company’s Slick State properties to its Bloomberg properties in order to secure more advantageous plant

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processing, transportation and gathering fees and access to gas markets. The pipeline system was installed, operational and ready to redirect the production in September 2008. The contract minimum commitment to Integrys is approximately 11.2 Bcf over a three year period for the pipeline interconnect. The amount of total commitment is $550,000 plus 8% interest per annum, for a total liability of approximately $0.6 million. The Company has delivered approximately $177,300 of this commitment through June 30, 2009. The Company has not recorded a liability for this commitment as it expects to meet the minimum physical delivery based on estimated anticipated production.

This contract is not considered a derivative, but has been designated as an annual sales contract under SFAS No. 133 (as amended).

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 material adverse effect on the Company’s financial condition, results of operations or cash flows except as set forth below.

David Blake, et al. v. Edge Petroleum Corporation — On September 19, 2005, David Blake and David Blake, Trustee of the David and Nita Blake 1992 Children’s Trust, filed suit against the Company in state district court in Goliad County, Texas alleging breach of contract for failure and refusal to transfer overriding royalty interests to plaintiffs in several leases in the Nita and Austin prospects in Goliad County, Texas and failure and refusal to pay monies to Blake pursuant to such overriding royalty interests for wells completed on the leases. The plaintiffs seek relief of (1) specific performance of the alleged agreement, including granting of overriding royalty interests by us to Blake; (2) monetary damages for failure to grant the overriding royalty interests; (3) exemplary damages for his claims of business disparagement and slander; (4) monetary damages for tortious interference; and (5) attorneys’ fees and court costs. Venue of the case was transferred to Harris County, Texas by agreement of the litigants. The Company’s subsidiaries, Edge Petroleum Exploration Company, Edge Petroleum Operating Company and Edge Petroleum Production Company, were also added as defendants. The Company filed a counterclaim against plaintiff and joined various related entities that are controlled by Blake, seeking lease interests in which the Company contends it had been wrongfully denied participation and also claiming that proprietary information was misappropriated. The parties have moved for summary judgment on each other’s claims and counterclaims, which the trial court has denied as to both sides. In November 2007, the Company filed a separate motion for summary judgment based on the statute of frauds and; the court has not yet ruled on this separate motion. In June 2008, the Plaintiffs filed a Sixth Amended Petition conditionally adding claims for certain prospects that had been previously settled by means of a Compromise and Settlement Agreement (the “Settlement Agreement”), entered in settlement of prior litigation among some of the parties, but only to the extent that rescission of the prior Settlement Agreement was being sought by the Company. The Company is not seeking rescission of the prior Settlement Agreement and responded accordingly in its Fourth Amended Original Counterclaim and Claims Against Additional Parties filed on October 16, 2008. On October 17, 2008, the plaintiffs filed their Seventh Amended Petition adding a claim for breach of the Settlement Agreement. In December 2008, one of the Blake counter-defendants filed a motion to arbitrate, which motion has not been heard by the court. The Company has responded and will continue to respond aggressively to this lawsuit, and believes it has meritorious defenses and counterclaims.

Mary Jane Carol Trahan Champagne, et al. v. Edge Petroleum Exploration Company, et al. — On September 19, 2008 the Company was sued in state district court in Vermilion Parish, Louisiana by Mary Jane Trahan, Carol Trahan Champagne and 29 other plaintiffs alleging breach of obligations under mineral leases in Vermilion Parish regarding the Trahan No. 1 well and the Trahan No. 3 well (MT RC SUB reservoir). Plaintiffs are seeking unspecified damages for lost revenue, lost royalties and devaluation of property interest sustained as a result of the defendants’ alleged negligent and improper drilling operations on the Trahan No. 1 well and the Trahan No. 3 well, including alleged failure to prevent underground water from flooding and destroying plaintiffs’ portion of the reservoir beneath plaintiffs’ property. Plaintiffs also allege defendants failed to “block squeeze” sections of the Trahan No. 3 well as would a prudent operator. This lawsuit, previously removed from the state court to the federal district court for the Western District of Louisiana, Lafayette Division, has been remanded to state court. The Company’s insurance carrier has retained counsel to represent the Company in this matter. The Company filed certain peremptory challenges and exceptions to the

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Plaintiffs’ petition, including prematurity, no cause of action and prescription. Except for the prescription challenge, these motions were overruled by the court in May, 2009. The Company has not established a reserve with respect to this claim and it is not possible to determine what, if any, its ultimate exposure might be in this matter. The Company intends to vigorously defend itself in this lawsuit.

John Lemke, et al. v. Edge Petroleum Corporation - In October 2008, the Company was sued in state district court in Harris County, Texas over an alleged contract to receive a royalty in certain areas in South Louisiana. The Company and the Plaintiffs settled the dispute by agreement pursuant to which the Company paid the Plaintiffs $17,500 in return for a full release of all claims and a dismissal of the lawsuit.

Lara Energy, Inc. v. Edge Petroleum Corporation - In June 2009, the Company was sued in state district court in Harris County, Texas by a working interest co-owner in the Chapman Ranch prospect located in Nueces County, Texas. Plaintiff alleges various theories of causes of action, including breach of contract, breach of duty of good faith and fair dealing, negligent misrepresentation, improper acquisition of leases and seismic data, fraudulent inducement and other causes of action. The Company believes it has done nothing wrong and has honored the contracts with the Plaintiff that govern operations in the Chapman Ranch prospect. The Company has filed an answer and intends to vigorously defend itself.

Encinitas Ranch et al v. ExxonMobil Corporation, et al . — This lawsuit was originally filed in state district court in Brooks County, Texas, against ExxonMobil, Chevron USA and other defendants alleging numerous causes of action relating to Plaintiffs’ lands going back several decades, including damage to the surface, improperly abandoned equipment, spills, contamination, trespass, failure to maintain facilities, improper or untimely payment of royalties, breach of express and implied covenants, and various acts of negligence, including an alleged incident regarding a fire that occurred on the ranch in 2008. Plaintiffs amended their petition in May 2008 to name additional defendants, including the Company. The Company has a non-operating interest in the Encinitas Ranch, and has never operated the wells or lease in Brooks County, Texas, covering Plaintiffs’ land. The Company’s liability insurance carrier is providing a defense to this matter under a reservation of rights, and has retained local counsel for the Company and filed an answer on the Company’s behalf. No trial date has been set. The Company believes it has meritorious defenses to this litigation and intends to vigorously defend itself.

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

The following is Management’s Discussion and Analysis (“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 MD&A 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, 2008 (“2008 Annual Report”).

FORWARD LOOKING STATEMENTS

The information contained in this quarterly Report on Form 10-Q includes certain forward-looking statements. The words “may,” “will,” “expect,” “anticipate,” “believe,” “continue,” “estimate,” “project,” “intend,” and similar expressions used in this Form 10-Q are intended to identify forward-looking statements within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. You should not place undue reliance on these forward-looking statements, which speak only as of the date made. We undertake no obligation to publicly release the result of any revision of these forward-looking statements to reflect events or circumstances after the date they are made or to reflect the occurrence of unanticipated events. You should also know that such statements are not guarantees of future performance and are subject to risks, uncertainties and assumptions. Should any of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may differ materially from those included within the forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, those set forth under “ITEM 1A. RISK FACTORS” of our 2008 Annual Report and this Quarterly Report on Form 10-Q.

GENERAL OVERVIEW

Edge Petroleum Corporation (“Edge”, “we” or the “Company”) is a Houston-based independent energy company that focuses its exploration, development, production, acquisition 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 a strategy which focused on a balanced program of exploration, exploitation and development and acquisition of oil and natural gas properties. In late 2007, in an attempt to enhance shareholder value we began to assess our strategic alternatives and have subsequently expanded this process to include a further evaluation of both our financial and strategic alternatives in late 2008 and continuing into 2009. Our current primary focus is on capital preservation and resolving the uncertainty and challenges we face.

We generate revenues, income and cash flows by producing and marketing oil and natural gas produced from our oil and natural gas properties. We have historically made significant capital expenditures in our exploration, development, and production activities that have allowed us to continue generating revenue, income and cash flows. In recent years, we have also spent considerable efforts on acquisitions, including both corporate and asset acquisitions. We are currently operating with a reduced capital spending program as we continue to pursue the sale of some or all of our assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company.

This overview provides our perspective on the individual sections of MD&A. Our MD&A includes the following sections:

· Outlook and Review of Financial and Strategic Alternatives — additional discussion relating to management’s outlook to the future of our business.

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· 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 natural gas industry.

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

· Divestitures — information about our sales and divestitures.

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

· Results of Operations — an analysis of our consolidated results for the periods presented in our financial statements.

· Liquidity and Capital Resources — an analysis of cash flows, sources and uses of cash, and contractual obligations.

· Fair Value Measurements — supplementary discussion regarding fair value measurements and implementation of SFAS No. 157, Fair Value Measurements.

· Risk Management Activities — supplementary information regarding our price-risk management activities.

· Tax Matters — supplementary discussion of income tax matters.

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

Outlook and Review of Financial and Strategic Alternatives

On December 18, 2007, we announced the hiring of a financial advisor to assist our Board of Directors with an assessment of strategic alternatives. During 2008, we focused our efforts on a proposed merger with Chaparral Energy, Inc. (“Chaparral”). However, on December 17, 2008, we announced the termination of the Chaparral merger agreement after both we and Chaparral determined it was highly unlikely that the conditions to the closing of the proposed merger would be satisfied or that Chaparral would be able to obtain sufficient debt and equity financing to allow them to complete the proposed merger and operate as a combined company, particularly in light of the challenging environment in the financial markets and the energy industry.

Since December 2008, we have continued with our evaluation and assessment of various financial and strategic alternatives in order to address our liquidity issues and the impending maturity of our Revolving Facility (see discussion below) on August 31, 2009. We are working with an investment banking firm to assist further in the evaluation of our financial and strategic alternatives.

During January 2009, we announced that the lenders (“Lenders”) to our Fourth Amended and Restated Credit Agreement (as amended, the “Revolving Facility”) had completed their borrowing base redetermination and reduced our borrowing base to $125 million, resulting in a $114 million borrowing base deficiency (the “Deficiency”).

Pursuant to the terms of the Revolving Facility, we initially elected to prepay the Deficiency in six equal monthly installments, with the first $19 million installment being due on February 9, 2009. We have entered into the following consents and amendments (collectively, the “Amendments”) with our Lenders in recent months as a result of the ongoing financial and strategic alternatives process:

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one month with the last of the six installment payments to be due on August 10, 2009. In connection with the February Consent, we prepaid $5.0 million of our outstanding advances under the Revolving Facility, in two equal installments of $2.5 million on February 9, 2009 and February 23, 2009, with each of these prepayments applied on a pro rata basis to reduce the six remaining $19 million deficiency payments.

· On March 10, 2009, we entered into a Consent and Agreement (the “March Consent”) with the Lenders under the Revolving Facility, which provided, among other things, for the extension of the due date for the first installment to repay the Deficiency from March 10, 2009 to March 17, 2009. Notwithstanding such extension, we agreed with the Lenders that each of the other five equal installment payments required to eliminate the Deficiency would be due and payable as provided for in the February Consent.

· On March 16, 2009, we entered into Consent and Amendment No. 4 to our Revolving Facility (the “Amended Consent”) which provided, among other things, (1) that we would make a $25 million payment on May 31, 2009 with all remaining principal, fees and interest amounts under our Revolving Facility to be due and payable on June 30, 2009, (2) that it would be an event of default (i) if we failed to have executed and delivered on or before May 15, 2009 at least one of the following (a) a commitment letter from a lender or group of lenders reasonably satisfactory to our Lenders providing for the provision by such lender or group of lenders of a credit facility in an amount sufficient to repay all of our obligations under the Revolving Facility on or before June 30, 2009, (b) a merger agreement or similar agreement involving us as part of a transaction that results in the repayment of our obligations under the Revolving Facility on or before June 30, 2009, and (c) a purchase and sale agreement with a buyer or group of buyers reasonably acceptable to our Lenders providing for a sale transaction by us that results in the repayment of all of our obligations under the Revolving Facility on or before June 30, 2009, or (ii) if we were in default under or our hedging arrangements have been terminated or cease to be effective without the prior written consent of our Lenders, (3) that our advances under the Revolving Facility would bear interest at a rate equal to the greater of (a) the reference rate publicly announced by Union Bank of California, N.A. for such day, (b) the Federal Funds Rate in effect on such day plus 0.50% and (c) a rate determined by the Administrative Agent to be the Daily One-Month LIBOR (as defined in the Revolving Facility), in each case plus 2.5% or, during the continuation of an event of default, plus 4.5% (resulting in an effective interest rate of approximately 5.75%), (4) for limitations on the making of capital expenditures and certain investments, and (5) for the elimination of the current ratio, leverage ratio and interest coverage ratio covenant requirements. The Amended Consent also eliminated the six $19 million deficiency payments which were contemplated by the February Consent and the March Consent.

· On May 15, 2009, we entered into Amendment No. 5 (“Amendment No. 5”) which provided for, among other things, (1) the elimination of the provision providing that it would be an event of default if we failed to have executed and delivered on or before May 15, 2009 at least one of the following (a) a commitment letter from a lender or group of lenders reasonably satisfactory to the lenders providing for the provision by such lender or group of lenders of a credit facility in an amount sufficient to repay all of our obligations under the Revolving Facility on or before June 30, 2009, (b) a merger agreement or similar agreement involving us as part of a transaction that resulted in the repayment of our obligations under the Revolving Facility on or before June 30, 2009, and (c) a purchase and sale agreement with a buyer or group of buyers reasonably acceptable to the Lenders providing for a sale transaction by us that resulted in the repayment of all of our obligations under the Revolving Facility on or before June 30, 2009 and (2) the elimination of certain reporting requirements relating to certificates to be provided by our auditors and responsible officers.

· On May 29, 2009, we entered into Amendment No. 6 (“Amendment No. 6”) which eliminated the May 31, 2009 payment obligation and provided that the related $25 million payment for outstanding advances as well as any unpaid interest thereon and all remaining principal, fees and interests amounts under the Revolving Facility would be due on June 30, 2009.

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on July 31, 2009 and (3) our agreement to make a prepayment of the advances under the Revolving Facility in the amount of $7.5 million with such prepayment to be made on or before July 10, 2009. We paid the July interest of approximately $1.1 million on July 1, 2009 and also paid $7.5 million on July 10, 2009.

· On July 31, 2009 we entered into Amendment No. 8 (“Amendment No. 8”) which changed the maturity date of our Revolving Facility from July 31, 2009 to August 31, 2009.

If we breach any of the provisions of the Amended Consent, subsequent Amendments or the Revolving Facility, our Lenders will be entitled to declare an event of default, at which point the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, would become immediately due and payable. In any event, the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, will be payable on August 31, 2009 unless earlier paid or a further extension with respect to payment is negotiated with our Lenders. Our Lenders may take action to enforce their rights with respect to the outstanding obligations under the Revolving Facility. Because substantially all of our assets are pledged as collateral under the Revolving Facility, if our Lenders declare an event of default, they would be entitled to foreclose on and take possession of our assets. In such an event, we may be forced to liquidate or to otherwise seek protection under Chapter 11 of the U.S. Bankruptcy Code. These matters, as well as the other risk factors related to our liquidity and financial position raise substantial doubt as to our ability to continue as a going concern. See ITEM 2. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — LIQUIDITY AND CAPITAL RESOURCES — REVOLVING FACILITY.” With respect to our compliance with the Amended Consent, there can be no assurance that we will be able to further negotiate the terms of the Amended Consent or negotiate a further restructuring of the related indebtedness or that we will be able to make any required payments when they become due. Moreover, there can be no assurance that we will be successful in our efforts to comply with the terms of the Amended Consent, including our ongoing efforts to evaluate and assess our various financial and strategic alternatives (which may include the sale of some or all of our assets, a merger or other business combination involving the Company, or the restructuring or recapitalization of the Company). If such efforts are not successful, we may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code. See Item 1A. RISK FACTORS .

Going Concern — In addition to the impending maturity of our Revolving Facility on August 31, 2009, the capital expenditures required to maintain and/or grow production and reserves are substantial. Prices for oil and natural gas declined materially during the fourth quarter of 2008, and natural gas prices continued to decline during the first half of 2009. A continued or extended decline in oil or natural gas prices will have a material adverse effect on our financial position, results of operations, cash flows and access to capital and on the quantities of oil and natural gas reserves that we can economically produce. Our stock price has significantly declined over the past year which also makes it more difficult to obtain equity financing on acceptable terms to address our liquidity issues. In addition, we are reporting negative working capital at June 30, 2009 and continue to report net losses in the first six months of 2009 following three consecutive years of net losses. Therefore, there is substantial doubt as to our ability to continue as a going concern for a period longer than the next twelve months. Additionally, our independent auditors included an explanatory paragraph in their report on our consolidated financials statements as of and for the year ended December 31, 2008 that raises substantial doubt about our ability to continue as a going concern. Our ability to continue as a going concern is dependent upon the success of our financial and strategic alternatives process, which may include the sale of some or all of our assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company and an increase in commodity prices. Until the possible completion of the financial and strategic alternatives process, our future remains uncertain and there can be no assurance that our efforts in this regard will be successful.

Our consolidated financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which implies we will continue to meet our obligations and continue our operations for the next twelve months. Realization values may be substantially different from carrying values as shown, and our consolidated financial statements do not include any adjustments relating to the recoverability or classification of recorded asset amounts or the amount and classification of liabilities that might be necessary as a result of this uncertainty.

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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, the results of our financial and strategic alternatives process, access to capital, the acquisitions market and factors referred to in “FORWARD LOOKING INFORMATION” in our 2008 Annual Report.

Industry and Economic Factors

In managing our business, we must deal with many factors inherent to our industry. First and foremost is the fluctuation of oil and natural gas prices. Our revenues, the value of our assets, our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in oil and natural gas prices and the costs to produce our reserves. Oil and natural gas prices are subject to significant fluctuations that are beyond our ability to control or predict without losing some advantage of the upside potential. In recent years, oil and natural gas commodity prices have generally trended upwards in response to robust demand and constrained supplies, with oil and natural gas prices peaking at more than $140.00 per barrel and $13.00 per Mcf, respectively, in July 2008. In late 2008 and early 2009, a world-wide economic recession and oversupply of natural gas in North America led to an unprecedented decline in oil and natural gas prices, with oil falling by more than $100.00 per barrel and natural gas falling more than $10.00 per Mcf from their peaks in July 2008. Although crude oil prices have shown some recovery in the second quarter of 2009 rising to approximately $70.00 per barrel, natural gas prices have remained weak around $3.00 to $4.00 per Mcf.

Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. Our costs and expenses tend to react to activity levels in our industry and commodity price movements. In response to the recent historically high commodity prices, the oil and natural gas industry experienced significant increases in activity and in demand for oil field services. The increased demand for these services resulted in significant inflation in both operating and capital costs in 2008. Although commodity prices have declined significantly in recent months, the inflated cost of oil field services resulting from recent historically high commodity prices did not decrease as rapidly. While these costs are declining, they have lagged in comparison to the rapid commodity price decline; thus the prospect of continued low commodity prices and disproportionately higher service costs will constrain the industry’s capital reinvestment for the near future.

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, oftentimes resulting in no commercially productive reserves being discovered. These factors, together with periods of increased demand for rigs, equipment, supplies and services, have made it difficult at times for us to further our growth, and made timely execution of our planned activities difficult.

Our business, as with other extractive businesses, is a depleting one in which each gas equivalent produced must be replaced or our asset base and capacity to generate revenues in the future will shrink. In 2008 and the first half of 2009, we were unable to replace the production we generated due to our reduced capital spending program and higher drilling and operating costs. This will continue to be a factor in 2009 as we operate under a severely limited capital and operating budget.

The oil and natural gas industry is highly competitive. We compete with major and diversified energy companies, independent oil and natural gas businesses and individual operators in exploration, production, marketing and acquisition activities. 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 natural gas wells and related facilities. These regulations may become more demanding in the future.

Poor economic conditions continue to create considerable challenges and uncertainties for the energy industry. We are unable to predict the impact on our business of a continued decline in commodity prices and

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the global economy, but the current conditions have made it difficult at times for us in our ongoing financial and strategic alternatives process. We expect that continued weakening in the economy could result in further declines in our revenue, cash flows and liquidity.

Approach to the Business

Historically, our goal has been to fund ongoing exploration and development projects with cash flow provided by operating activities, occasionally supplemented with external sources of capital. In connection with our ongoing financial and strategic alternatives process and our liquidity issues resulting from the impending maturity of our Revolving Facility on August 31, 2009 and the related Amended Consent and subsequent Amendments, we have operated and will continue to operate with a severely limited capital spending program in 2009 as we continue to pursue the sale of some or all of our assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company. Our strategy is currently to continue under a severely limited capital and operating budget, thereby reducing our normal exploration and development activities as we seek to preserve liquidity and resolve the uncertainty and challenges that we face as we pursue various financial and strategic alternatives.

We normally hedge our exposure to volatile oil and natural gas prices on a portion of our expected production to reduce price risk. As of June 30, 2009, we had derivative contracts in place covering 20,000 MMBtu/d of natural gas and 300 Bbl/d of crude oil for the remainder of 2009.

Divestitures

We regularly review our asset base for the purpose of identifying non-core assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. While we generally do not dispose of assets solely for the purpose of reducing debt, such dispositions can have the result of furthering our objective of financial flexibility through reduced debt levels. During the first half of 2009, we completed the sale of various non-core properties in Texas for proceeds of $0.3 million and during the first half of 2008, we completed the sale of certain working interests in approximately 100 properties located in Texas to various buyers for aggregate proceeds of approximately $18.2 million.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue, 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 and Natural Gas Reserves - Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic

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and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment, as well as prices and cost levels at that point in time. 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 is used in calculating depletion expense and 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 natural gas properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full-cost ceiling test. The ceiling is the discounted present value of our estimated total proved reserves (using a 10% discount rate) adjusted for taxes and the impact of cash flow hedges on pricing, if cash flow hedge accounting is applied. The ceiling test calculation dictates that prices and costs in effect as of the last day of the period are to be used in calculating the discounted present value of our estimated total proved reserves. However, if prices increase subsequent to the balance sheet date, but before the filing date, Securities and Exchange Commission (“SEC”) guidelines allow a company to use the subsequent date’s higher prices in calculating the full-cost ceiling. 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 natural gas properties is not reversible at a later date even if oil and natural gas prices increase. A ceiling test impairment could result in a significant loss for a reporting period; however, future depletion expense would be correspondingly reduced. Our estimated proved reserves volumes have decreased during the period from year-end 2008 to June 30, 2009, but the average oil, NGL and natural gas prices at the balance sheet date as of June 30, 2009 were $69.89 per barrel, $41.93 per barrel and $3.89 per MMBtu, respectively. We were not required to record an impairment during the second quarter of 2009. The impairments taken in the third and fourth quarters of 2008 and first quarter of 2009 significantly impacted our depletion expense in the second quarter of 2009. If the 2008 and 2009 impairments had not been taken, our depletion rate would have been approximately $6.25 per Mcfe as compared to $2.43 per Mcfe reported for the three months ended June 30, 2009.

Effect if Different Assumptions Used: Units-of-production method to amortize our oil and natural gas properties - A 10% increase or decrease in reserves would have decreased or increased, respectively, our depletion expense for the quarter by approximately 10%.

“Ceiling” limitation test - Factors that contribute to a ceiling test impairment include the price used to calculate the reserve limitation threshold and reserve quantities. A reduction in prices at a measurement date could trigger a full-cost ceiling impairment. We recorded an impairment of approximately $78.3 million, net of tax, at March 31, 2009, but we are reporting a cushion of approximately $51.7 million, net of tax, at June 30, 2009. A 10% increase or decrease in prices would have decreased or increased our cushion by approximately 70%, net of tax, respectively. If however, prices should decline in the third or fourth quarter of 2009, the potential for additional impairments at upcoming quarter-ends exists. Although our hedging program is intended to mitigate the economic impact of any significant price decline, it did not impact our ceiling test at June 30, 2009 because we do not apply cash flow hedge accounting to our derivative contracts. Had we applied cash flow hedge accounting to our outstanding derivative contracts, there would have been a 27% increase in the cushion we calculated as a result of the low prices at the measurement date falling below the derivative price floors. A 10% increase or decrease in reserve volume would have decreased or increased the cushion calculated at June 30, 2009 by approximately 40%.

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 natural gas production operations. Our

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removal and restoration obligations are primarily associated with plugging and abandoning wells. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations, we estimate asset retirement costs for all of our assets upon acquisition of the asset, adjust those costs for inflation 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. When new obligations are incurred, i.e. a new well is drilled or acquired, we add to the ARO liability. Should either the estimated life or the estimated abandonment costs of a property change upon our quarterly review, our estimate must be revised. When well obligations are relieved by sale of the property or plugging and abandoning the well, the related estimated liability and asset costs are removed from our balance sheet and replaced by the costs actually spent on retiring the asset.

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.

Assumptions/Approach 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 independent engineering firms to evaluate our properties annually. We use the remaining estimated useful life from the period-end reserve reports prepared by our independent reserve engineers 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 have developed a standard cost estimate based on historical costs, industry quotes and depth of wells. This cost estimate is reviewed annually to determine whether it is a reasonable estimate in the current environment. Unless we expect a well’s plugging to be significantly different than a normal abandonment, we use this estimate.

Effect if Different Assumptions Used: We expect to see our calculations for new properties and revisions to existing properties impacted significantly if interest rates rise, as the credit-adjusted-risk-free rate is one of the variables used on a quarterly basis. We also expect that significant changes to the cost of retiring assets or the reserve life of our assets would have significant impact on our estimated ARO.

Nature of Critical Estimate Item: Income Taxes - In accordance with SFAS No. 109, Accounting for Income Taxes, we have recorded a deferred tax asset and liability to account for the expected future tax benefits and consequences, respectively, of events that have been recognized in our financial statements and our tax returns. There are several items that result in deferred tax assets and liabilities on the balance sheet, the largest of which are attributable to tax basis in excess of book basis in oil and natural gas properties and the impact of net operating loss (“NOL”) carryforwards. We routinely assess our ability to use all 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 to remove the benefit of those NOL carryforwards from our financial statements. Additionally, in accordance with Financial Accounting Standards Board (“FASB”) Interpretation 48, Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109 (“FIN 48”) we have recorded a liability of $0.1 million associated with uncertain tax positions. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We are required to determine whether it is more likely than not (a likelihood of more than 50 percent) that a tax position will be sustained upon examination, including resolution of

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any related appeals or litigation processes, based on the technical merits of the position in order to record any financial statement benefit. If that step is satisfied, then we must measure the tax position to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.

Assumptions/Approach Used: Numerous judgments and assumptions are inherent in the determination of future taxable income and tax return filing positions that we take, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices).

Effect if Different Assumptions Used: Along with consultation from an independent public accounting firm used in tax consultation, we continually evaluate complicated tax law requirements and their effect on our current and future tax liability and our tax filing positions. Despite our attempt to make an accurate estimate, the ultimate utilization of our NOL carryforwards is highly dependent upon our actual production, the realization of taxable income in future periods, Internal Revenue Code Section 382 limitations and potential tax elections. 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 be required to record a valuation allowance to remove the benefit of those NOL carryforwards from our financial statements, as was done most recently in the fourth quarter of 2008 and the first and second quarters of 2009. Our liability for uncertain tax positions is dependent upon our judgment on the amount of financial statement benefit that an uncertain tax position will realize upon ultimate settlement and on the probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of financial statement benefit. To the extent that a valuation allowance or uncertain tax position is established or increased or decreased during a period, we may be required to include an expense or benefit within tax expense in the statement of operations. During the first half of 2009, we recorded a valuation allowance of approximately $30.2 million which completely offset deferred tax assets recorded during the first half of 2009. This valuation allowance was recorded as a result of our anticipated inability to utilize all of our deferred tax assets.

Nature of Critical Estimate Item: Derivative and 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) related to our expected oil and natural gas production to seek to achieve a more predictable cash flow, as well as to reduce exposure from commodity price fluctuations. While these transactions are intended to be 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, Accounting for Derivative Instruments and Hedging Activities (as amended), all derivatives, other than those that meet the normal purchases and sales exception, are recorded on the balance sheet at fair value.

Cash Flow Hedge Accounting - For transactions accounted for under cash flow hedge accounting treatment, the effective portion of the change in fair value of outstanding derivative contracts is deferred through other comprehensive income (“OCI”) on the balance sheet, rather than recorded immediately in total revenue on the statement of operations. Ineffective portions of the changes in the fair value of the derivative contracts are recognized in total revenue as they occur. While the hedge contract is outstanding, the fair value may increase or decrease until settlement of the contract. The cash flows resulting from settlement of derivative transactions which relate to economically hedging our physical production volumes are classified in operating activities on the statement of cash flows, and the cash flows resulting from settlement of derivative transactions considered “overhedged” positions are classified in investing activities on the statement of cash flows.

Mark-to-Market Accounting - For transactions accounted for using mark-to-market accounting treatment, until the contract settles, the entire change in the fair value of the outstanding derivative contract is recorded in total revenue immediately, and not deferred through OCI, and there is no

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measurement of effectiveness. Since January 1, 2006, we have applied mark-to-market accounting treatment to all outstanding derivative contracts.

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 derivatives. We currently obtain and review 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. It also approximates the fair value of the contracts as it would be the cost to us to terminate a contract at that point in time, as well as the potential inflows or outflows of cash at the expiration of the contracts. Due to the fact that we apply mark-to-market accounting treatment, the offset to the balance sheet asset or liability, or the change in fair value of the contracts, is included in total revenue on the statement of operations rather than deferred in OCI on the balance sheet.

Effect if Different Assumptions Used: At June 30, 2009, a 10% change in the commodity price per unit would cause the fair value total of our derivative financial instruments to increase or decrease by approximately $1.2 million. Had we applied cash flow hedge accounting treatment to all of our derivative contracts outstanding at June 30, 2009, our net loss to common stockholders for the six months would have been approximately $61.0 million, or $2.26 per basic and diluted loss per share, assuming that all hedges were fully effective, as compared to our reported net loss to common stockholders for the six months ended June 30, 2009 of $86.3 million, or $3.13 basic and diluted loss per share.

Results of Operations

This section includes discussion of our results of operations for the three and six months ended June 30, 2009 as compared to the same period of the prior year. We are an independent oil and natural gas company engaged in the exploration, development, acquisition and production of crude oil and natural gas properties in the United States. 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 Texas, Mississippi, New Mexico and Louisiana.

Second Quarter 2009 Compared to the Second Quarter 2008

Revenue and Production

Total revenue increased significantly from the second quarter of 2008 to the comparable 2009 period. Excluding the effects of derivative activity, revenue decreased 76% from the second quarter of 2008 to the comparable 2009 period. For the three months ended June 30, 2009 and 2008, our product mix contributed the following percentages of revenue and production volumes:

				REVENUE (2)				PRODUCTION
	REVENUE (1)			Three Months Ended June 30,				VOLUMES (MCFE)
	2009		2008	2009		2008		2009		2008
Natural gas	64	%	*	57	%	67	%	67	%	71	%
Natural gas liquids	18	%	*	18	%	14	%	21	%	18	%
Crude oil and condensate	18	%	*	25	%	19	%	12	%	11	%
			*
Total	100	%	*	100	%	100	%	100	%	100	%

(1) Includes effect of derivative transactions

(2) Excludes effect of derivative transactions

* Not meaningful due to derivative losses

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The following table summarizes volume and price information with respect to our oil and natural gas production:

						2009 Period Compared
						to 2008 Period
	Three Months Ended					$			%
	June 30,					Increase			Increase
	2009		2008			(Decrease)			(Decrease)
	(in thousands, except prices and percentages)
Production Volumes:
Natural gas (MMcf)	2,006		3,042			(1,036		)	(34	)%
Natural gas liquids (MBbls)	107		126			(19		)	(15	)%
Crude oil and condensate (MBbls)	58		77			(19		)	(25	)%
Natural gas equivalent (MMcfe)	2,996		4,260			(1,264		)	(30	)%
Average Sales Price(1):
Natural gas ($ per Mcf)(2)	$	3.28	$	10.84		$	(7.56	)	(70	)%
Natural gas liquids ($ per Bbl)	20.23		53.08			(32.85		)	(62	)%
Crude oil and condensate ($ per Bbl)(2)	50.41		122.57			(72.16		)	(59	)%
Natural gas equivalent ($ per Mcfe)(2)	3.90		11.52			(7.62		)	(66	)%
Natural gas equivalent ($ per Mcfe)(3)	3.93		(1.77		)	5.70			*
Operating Revenue:
Natural gas (2)	$	6,594	$	32,950		$	(26,356	)	(80	)%
Natural gas liquids	2,156		6,718			(4,562		)	(68	)%
Crude oil and condensate (2)	2,924		9,392			(6,468		)	(69	)%
Gain (loss) on derivatives	109		(56,598		)	56,707			100	%
Total revenue	$	11,783	$	(7,538	)	$	19,321		*

* Not meaningful

(1) Prices are calculated based on whole numbers, not rounded numbers.

(2) Excludes the effect of derivative transactions.

(3) Includes the effect of derivative transactions.

Production — For the quarter ended June 30, 2009, production volumes decreased as compared to the same 2008 period primarily due to normal production declines, asset sales completed during early 2008 and decreased capital re-investment in replacing and maintaining production as compared to historical levels. The following summarizes our average daily production volumes:

	For the Three Months Ended June 30,
	2009	2008
Production Volumes per Day:
Natural gas (MMcf/D)	22.0	33.4
Natural gas liquids (MBbls/D)	1.2	1.4
Oil and condensate (MBbls/D)	0.6	0.8
Natural gas equivalent (MMcfe/D)	32.9	46.8

Average sales price — Our sales revenue is sensitive to the 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. In recent years, oil and natural gas commodity prices have generally trended upwards in response to robust demand and constrained supplies, with oil and natural gas prices peaking at more than $140.00 per barrel and $13.00 per Mcf, respectively, in July 2008. In the second half of 2008, a world-wide

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economic recession and oversupply of natural gas in North America led to an unprecedented decline in oil and natural gas prices, with oil falling by more than $100.00 per barrel and natural gas falling more than $10.00 per Mcf from their peaks in July 2008. Although crude oil prices have shown some recovery in the second quarter of 2009 rising to approximately $70.00 per barrel, natural gas prices have remained weak around $3.00 to $4.00 per Mcf. This has significantly affected our business, but in 2009 our commodity derivatives have provided some protection against these falling prices, see “Derivative” discussion below. A continued or extended decline in oil or natural gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital and on the quantities of oil and natural gas reserves that we can economically produce.

Natural gas revenue - For the three months ended June 30, 2009, natural gas revenue, excluding derivative activity, decreased 80% over the same period in 2008 due to both lower average realized prices and production volumes. The overall decrease in production compared to the prior year period resulted in a decrease in revenue of approximately $11.2 million (based on 2008 comparable period pre-derivative prices). The decrease in average price received, excluding derivative activity, resulted in decreased revenue of approximately $15.2 million (based on current period production). See below for a discussion of the impact of natural gas derivatives on prices and revenue.

Natural gas liquids (“NGL”) revenue - For the three months ended June 30, 2009, NGL revenue decreased 68% over the same period in 2008 due to decreases in prices realized and production volumes. The price decrease resulted in a decrease in revenue of approximately $3.5 million (based on current period production). The decrease in NGL production decreased revenue by approximately $1.1 million (based on 2008 comparable period average prices).

Crude oil and condensate revenue - For the three months ended June 30, 2009, oil and condensate sales revenue, excluding derivative activity, decreased 69% from the comparable period in 2008 due to both lower average realized prices and production volumes. The decreased average realized price for oil and condensate for the three months ended June 30, 2009 resulted in a decrease in revenue of approximately $4.2 million (based on current period production). The decrease in oil and condensate production resulted in a decrease in revenue of approximately $2.3 million (based on 2008 comparable period pre-derivative prices). See below for a discussion of the impact of crude oil derivatives on prices and revenue.

Derivatives — The volume and price contract terms of our derivative contracts vary from period to period and therefore interact differently with the changing pricing environment, which makes the comparability of the results for each period difficult. In all periods presented, we applied mark-to-market accounting treatment to our derivative contracts; therefore the full volatility of the non-cash change in fair value of our outstanding contracts is reflected in total revenue and will continue to affect total revenue until outstanding contracts expire. Since these gains/losses are not a function of the operating performance of our oil and natural gas assets, excluding their impact from the above discussions helps isolate the operating performance of those assets. The following table summarizes the various components of the total gain or loss on derivatives for each of the periods indicated and the impact each component had on our realized prices:

	Three Months Ended June 30,
	2009						2008
	$			$ per unit (1)			$			$ per unit(1)
	(in thousands, except per unit prices)
Natural gas derivative contract settlements (Mcf)	$	7,744		$	3.86		$	(6,733	)	$	(2.21	)
Crude oil derivative contract settlements (Bbl)	284			4.89			(7,916		)	(103.31		)
Mark-to-market unrealized change in fair value of gas derivative contracts (Mcf)	(6,744		)	(3.36		)	(30,914		)	(10.17		)
Mark-to-market unrealized change in fair value of oil derivative contracts (Bbl)	(1,175		)	(20.25		)	(11,035		)	(144.01		)
Gain (loss) on derivatives (Mcfe)	$	109		$	0.03		$	(56,598	)	$	(13.29	)

(1) Prices per unit are calculated based on whole numbers, not rounded numbers.

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Should crude oil or natural gas prices increase or decrease from the current levels, it could materially impact our revenues. In a high price environment, hedged positions could result in lost opportunities if there is a cap in place, thus lowering our effective realized prices on hedged production, but in an environment of falling prices, these transactions offer some pricing protection for hedged production. Due to the ongoing financial and strategic alternatives process the Company has not entered into any new derivative contracts in recent months and does not expect to for the foreseeable future, therefore beyond 2009 we will not be impacted by the benefits or consequences of derivative contracts.

Costs and Operating Expenses

The table below details our expenses:

						2009 Period Compared to 2008 Period
	Three Months Ended June 30,					$ Increase			% Increase
	2009		2008			(Decrease)			(Decrease)
	(in thousands, except percentages)
Oil and natural gas operating expenses	$	3,824	$	3,941		$	(117	)	(3	)%
Severance and ad valorem taxes	1,257		3,297			(2,040		)	(62	)%
Depletion, depreciation, amortization and accretion:
Oil and natural gas property and equipment	7,285		21,237			(13,952		)	(66	)%
Other assets	171		184			(13		)	(7	)%
ARO accretion	93		101			(8		)	(8	)%
General and administrative expenses	4,919		5,152			(233		)	(5	)%
Total operating expenses	$	17,549	$	33,912		$	(16,363	)	(48	)%

Other income and expense, net	3,603		2,491			1,112			45	%
Income tax benefit	—		(16,118		)	16,118			100	%
Preferred stock dividends	—		2,067			(2,067		)	(100	)%

Oil and natural gas operating expenses - Oil and natural gas operating expenses include direct operating costs, repairs and maintenance and workover expenses. Although operating expenses for the three months ended June 30, 2009 were comparable to the same prior year period, our base costs were actually lower in the three months ended June 30 2009 as compared to the same period in 2008, but were offset partially by an increase in workover expenses incurred in the second quarter of 2009. Average oil and natural gas operating expenses were $1.28 per Mcfe and $0.93 per Mcfe for the three months ended June 30, 2009 and 2008, respectively. On a per Mcfe basis, the decline in production volume was the primary reason for the increase in cost per Mcfe.

Severance and ad valorem taxes - Severance tax expense for the three months ended June 30, 2009 was 80% lower than the prior year period as a result of the lower revenue received in the current year. In addition, our effective severance tax rate was lower due to abatements received during the first quarter of 2009. For the three months ended June 30, 2009, severance tax expense was approximately 5.2% of revenue subject to severance taxes compared to 6.1% of revenue subject to severance taxes for the second quarter of 2008. Ad valorem tax expense for the second quarter of 2009 was significantly higher than the second quarter of 2008 due to timing differences in recording costs in 2008 as compared to 2009, but the estimated expense for 2009 is expected to be lower overall than 2008 due to lower property valuations. On an equivalent basis, severance and ad valorem taxes averaged $0.42 per Mcfe and $0.77 per Mcfe for the three months ended June 30, 2009 and 2008, respectively.

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Depletion, depreciation, and amortization (“DD&A”) and accretion - Full-cost depletion on our oil and natural gas properties has decreased substantially as a result of a decrease in our depletion rate and 30% lower production volumes in the second quarter of 2009 compared to the second quarter of 2008. Our depletion rate for the three months ended June 30, 2009 was $2.43 per Mcfe, a 51% decrease compared to the second quarter 2008 rate of $4.99 per Mcfe. The depletion rate has decreased over the past year due to significant impairments taken in the third and fourth quarters of 2008 and first quarter of 2009. Depreciation of other assets for the second quarter of 2009 was comparable to the same period in 2008. Accretion expense associated with our ARO for the three months ended June 30, 2009 decreased due to revisions in the ARO liability made during 2008.

General and administrative (“G&A”) expenses — G&A expense decreased 5% for the three months ended June 30, 2009 compared to the same period in 2008 due primarily to the decrease in our salary and benefit costs as a result of the 36% drop in our staffing levels since June 30, 2008. We also had a decrease in general legal fees in the three months ended June 30, 2009 as compared to the same period of 2008. Partially offsetting these decreases were the costs associated with our ongoing financial and strategic alternative process that increased significantly from $0.7 million in the three months ended June 30, 2008 to $1.9 million for the three months ended June 30, 2009. We also had an increase in contract labor costs in 2009. Capitalized G&A costs for second quarter 2009 and 2008 were approximately $0.6 million and $1.1 million, respectively. G&A on a unit-of-production basis for the three months ended June 30, 2009 was $1.64 per Mcfe compared to $1.21 per Mcfe for the comparable 2008 period. G&A, excluding non-cash share-based compensation costs and bad debt expense, for the three months ended June 30, 2009 averaged $1.54 per Mcfe compared to $1.06 per Mcfe in the same period in 2008.

Other income and expense - During the three months ended June 30, 2009, our other income and expense increased primarily due to an increase in gross interest expense resulting from higher interest rates applied to our outstanding debt balance. For the second quarter of 2009, we capitalized less interest due to a 14% lower unproved property base on which we calculate interest expense subject to capitalization.

	Three Months Ended June 30,
	2009			2008
	(in thousands)
Gross interest expense	$	3,363		$	2,883
Less: capitalized interest	(294		)	(599		)
Interest expense, net	$	3,069		$	2,284

Weighted average debt	$	234,000		$	243,385

We recorded amortization of deferred loan costs related to our Revolving Facility during the three months ended June 30, 2009 and 2008. These costs for 2009 were higher than the prior year due to changes to the maturity date of our Revolving Facility which resulted in acceleration of the amortization.

Income tax benefit — We did not record a tax benefit for the three months ended June 30, 2009. We fully provided for additions to our deferred tax asset with a valuation allowance during the period. During the three months ended June 30, 2008, we recorded an income tax benefit of $16.1 million with no valuation allowance.

Preferred stock dividends — Our Board of Directors did not declare quarterly dividends on our 5.75% Series A cumulative convertible perpetual preferred stock in December 2008, March 2009 or June 30, 2009. Such dividends were declared in December 2007, March 2008 and June 2008. As a result, there is no dividend expense reported for the three months ended June 30, 2009 compared to $2.1 million for the same period in 2008.

Loss per share — We reported a net loss for the quarters ended June 30, 2009 and 2008. The loss in the second quarter of 2009 was primarily due to reduced revenues as a result of lower prices and production. Basic weighted average shares outstanding for the three months ended June 30, 2009 and 2008 were comparable. At June 30, 2009 and 2008, we excluded the effect of restricted stock units, common stock options, and 8.7 million shares of if-converted common stock from the diluted shares calculations because they would have an anti-dilutive effect on loss per share.

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Six Months Ended June 30, 2009 Compared to the Six Months Ended June 30, 2008

Revenue and Production

Total revenue increased significantly from the first six months of 2008 to the comparable 2009 period primarily as a result of our derivative activity. Excluding the effects of derivative activity, revenues decreased 74% from the first six months of 2008 to the comparable 2009 period. The Company’s decrease in revenue from the first six months of 2008 to the comparable 2009 period was primarily due to (1) commodity pricing that was significantly lower than first six months of 2008 and (2) a decrease in capital expenditures and drilling activity resulting from the decreased commodity prices which caused several proved undeveloped locations to be uneconomic and shortening the economic life of many other properties. Our product mix contributed the following percentages of revenues and production volumes:

				REVENUES (2)				PRODUCTION
	REVENUES (1)			Six months ended June 30,				VOLUMES (MCFE)
	2009		2008	2009		2008		2009		2008
Natural gas	77	%	*	63	%	64	%	68	%	70	%
Natural gas liquids	11	%	*	17	%	17	%	20	%	20	%
Crude oil and condensate	12	%	*	20	%	19	%	12	%	10	%

Total	100	%	*	100	%	100	%	100	%	100	%

(1) Includes effect of derivative transactions

(2) Excludes effect of derivative transactions

* Not meaningful due to derivative losses

The following table summarizes volume and price information with respect to our oil and natural gas production for the six months ended June 30, 2009 and 2008:

						2009 Period Compared
						to 2008 Period
	Six Months Ended					$			%
	June 30,					Increase			Increase
	2009		2008			(Decrease)			(Decrease)
	(in thousands, except prices and percentages)
Production Volumes:
Natural gas (MMcf)	4,176		6,815			(2,639		)	(39	)%
Natural gas liquids (MBbls)	204		317			(113		)	(36	)%
Crude oil and condensate (MBbls)	117		162			(45		)	(28	)%
Natural gas equivalent (MMcfe)	6,102		9,689			(3,587		)	(37	)%
Average Sales Price(1):
Natural gas ($ per Mcf)(2)	$	3.72	$	9.05		$	(5.33	)	(59	)%
Natural gas liquids ($ per Bbl)	20.33		51.54			(31.21		)	(61	)%
Crude oil and condensate ($ per Bbl)(2)	42.78		111.23			(68.45		)	(62	)%
Natural gas equivalent ($ per Mcfe)(2)	4.04		9.91			(5.87		)	(59	)%
Natural gas equivalent ($ per Mcfe)(3)	5.88		1.04			4.84			*
Operating Revenue:
Natural gas (2)	$	15,522	$	61,694		$	(46,172	)	(75	)%
Natural gas liquids	4,137		16,345			(12,208		)	(75	)%
Crude oil and condensate (2)	5,013		18,037			(13,024		)	(72	)%
Gain (loss) on derivatives	11,177		(85,957		)	97,134			*
Total revenue	$	35,849	$	10,119		$	25,730		*

(1) Prices are calculated based on whole numbers, not rounded numbers.

(2) Excludes the effect of derivative transactions.

(3) Includes the effect of derivative transactions.

* Not meaningful

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Production — For the six months ended June 30, 2009, production volumes decreased as compared to the same 2008 period primarily due to normal production declines, asset sales completed during early 2008 and decreased capital re-investment in replacing and maintaining production as compared to historical levels. The following summarizes our average daily production volumes:

	For the Six Months Ended June 30,
	2009	2008
Production Volumes per Day:
Natural gas (MMcf/D)	23.1	37.4
Natural gas liquids (MBbls/D)	1.1	1.7
Oil and condensate (MBbls/D)	0.6	0.9
Natural gas equivalent (MMcfe/D)	33.7	53.2

Average Sales Price — Our sales revenue is sensitive to the volatility of commodity prices. 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 - For the first half of 2009, natural gas revenue, excluding derivative activity, decreased due to lower production volumes and lower realized prices. The decrease in production volumes compared to the prior year period resulted in decreased revenue of approximately $23.9 million (based on 2008 comparable period pre-derivative prices). The decrease in average price received resulted in decreased revenue of approximately $22.3 million (based on current period production). See below for a discussion of the impact of natural gas derivatives on prices and revenue.

NGL revenue - For the six months ended June 30, 2009, NGL sales revenue decreased 75% over the same period in 2008 as a result of both lower production volumes and average realized prices. We do not hedge our NGL production. Decreased NGL production volumes led to decreased revenue of approximately $5.9 million (based on 2008 comparable period prices). Lower average realized NGL prices for the six months ended June 30, 2009 resulted in decreased revenue of approximately $6.3 million (based on current period production).

Crude oil and condensate revenue - For the six months ended June 30, 2009, oil and condensate sales revenue, excluding derivative activity, decreased 72% as compared to the same period in 2008, due to lower average realized prices and production. Lower average realized prices resulted in decreased revenue of approximately $8.0 million (based on current period production). The decrease in oil and condensate production resulted in a decrease in revenue of approximately $5.0 million (based on 2008 comparable period pre-derivative prices).

Derivatives — The volume and price contract terms of our derivative contracts vary from period to period and therefore interact differently with the changing pricing environment, which makes the comparability of the results for each period difficult. In both periods, we applied mark-to-market accounting treatment to our derivative contracts; therefore the full volatility of the non-cash change in fair value of our outstanding contracts is reflected in revenue and will continue to affect revenue until the contracts expire. Since these gains/losses are not a function of the operating performance of our oil and natural gas assets, excluding their impact from the above discussions helps isolate the operating performance of those assets. The following table summarizes the various components of the total gain or loss on derivatives and the impact each component had on our realized prices.

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	Six Months Ended June 30,
	2009						2008
	$			$ per unit (1)			$			$ per unit(1)
	(in thousands, except per unit prices)
Natural gas contract settlements (Mcf)	$	12,869		$	3.08		$	(6,370	)	$	(0.93	)

Crude oil contract settlements (Bbl)	1,007			8.59			(12,278		)	(75.72		)

Mark-to-market reversal of prior period unrealized change in fair value of gas derivative contracts (Mcf)	(13,390		)	(3.21		)	(2,626		)	(0.39		)

Mark-to-market unrealized change in fair value of gas derivative contracts (Mcf)	12,494			2.99			(53,852		)	(7.90		)

Mark-to-market reversal of prior period unrealized change in fair value of oil derivative contracts (Bbl)	(2,015		)	(17.21		)	14,954			92.23

Mark-to-market unrealized change in fair value of oil derivative contracts (Bbl)	212			1.83			(25,785		)	(159.02		)

Gain (loss) on derivatives (Mcfe)	$	11,177		$	1.84		$	(85,957	)	$	(8.87	)

(1) Prices per unit are calculated based on whole numbers, not rounded numbers.

Should crude oil or natural gas prices increase or decrease from the current levels, it could materially impact our revenues. Our physical sales of these commodities are vulnerable to the volatility of market price movements. Therefore, we have entered into contracts covering a portion of our anticipated 2009 production to ensure certain cash flows that we expect will allow us to plan our business activities. In a high price environment, hedged positions could result in lost opportunities if there is a cap in place, thus lowering our effective realized prices on hedged production, but in an environment of falling prices, these transactions offer some pricing protection for hedged production. Due to the ongoing financial and strategic alternatives process the Company has not entered into any new derivative contracts in recent months and does not expect to for the foreseeable future, therefore beyond 2009 we will not be impacted by the benefits or consequences of derivative contracts. Our 2008 derivative position exceeded our 2008 production exposing us to greater cash losses and risk of losses during that period.

Costs and Operating Expenses

The table below details our expenses:

						2009 Period Compared to 2008 Period
	Six Months Ended June 30,					$ Increase			% Increase
	2009		2008			(Decrease)			(Decrease)
	(in thousands, except percentages)
Oil and natural gas operating expenses	$	7,649	$	8,413		$	(764	)	(9	)%
Severance and ad valorem taxes	2,348		5,482			(3,134		)	(57	)%
Depletion, depreciation, amortization and accretion:
Oil and gas property and equipment	17,089		48,325			(31,236		)	(65	)%
Other assets	347		377			(30		)	(8	)%
ARO accretion	192		191			1			1	%
Impairment of oil and natural gas properties	78,254		—			78,254			100	%
General and administrative expenses	9,514		9,212			302			3	%
Total operating expenses	$	115,393	$	72,000		$	43,393		60	%

Other income and expense, net	$	6,765	$	6,885		$	(120	)	(2	)%
Income tax benefit	—		(24,764		)	24,764			100	%
Preferred stock dividends	—		4,133			(4,133		)	(100	)%

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Oil and natural gas operating expenses - For the six months ended June 30, 2009, operating expenses decreased as compared to the same period of 2008 due primarily to decreased well workover activity in 2009 and asset divestitures that occurred in 2008. However, we had an overall increase in our average oil and natural gas operating expenses, which were $1.25 per Mcfe for the six months ended June 30, 2009 as compared to $0.87 per Mcfe in the same period of 2008 as a result of the production declines in 2009 as compared to 2008.

Severance and ad valorem taxes - For the six months ended June 30, 2009, severance and ad valorem taxes decreased significantly from the first half of 2008. Severance tax expense for the six months ended June 30, 2009 was 78% lower than the prior year period due primarily to decreased realized rates. Our severance tax expense is levied on our oil and natural gas revenue from physical production (i.e. excluding derivative activity). For the six months ended June 30, 2009, severance tax expense was approximately 5.0% of revenue subject to severance taxes compared to 5.6% of revenue subject to severance taxes for the first half of 2008. Ad valorem tax expense for the first half of 2009 was significantly higher than the prior year because our 2007 year-end estimates were too high which impacted 2008 offsetting normal expense completely. On an equivalent basis, severance and ad valorem taxes averaged $0.38 per Mcfe and $0.57 per Mcfe for the six months ended June 30, 2009 and 2008, respectively.

DD&A and accretion - Depletion on our oil and natural gas properties decreased for the first half of 2009 compared to the same period of 2008 due to an decrease in our unit-of-production depletion rate and production volumes, which are discussed under “Revenue and Production” above. The depletion rate decreased from $4.99 per Mcfe in the first half of 2008 to $2.80 per Mcfe in the first half of 2009, primarily as a result of the impairments of our oil and natural gas properties taken during the second half of 2008 and the first quarter of 2009. Depreciation of furniture and fixtures and accretion expense for the first half of 2009 were comparable to the first half of 2008.

G&A expense - G&A expense for the first six months of 2009 was comparable to the same period of 2008. Although it was comparable in total, we had two primary offsetting items that contributed to the variance. We recorded an increase in costs of our ongoing financial and strategic alternatives process from $0.7 million in the first half of 2008 to $3.6 million in the first half of 2009. This increase was completely offset by a $3.7 million decrease in salaries and benefit costs related to our reduced workforce. We also had increases in contract labor costs, bad debt expense and building rent, which were partially offset by decreases in general legal expenses. During the first half of 2009 and 2008, we recorded bad debt expense of approximately $0.3 million and $0.1 million, respectively, to increase our reserve allowance on certain accounts receivable that we believe to be potentially uncollectible. G&A expense is typically reduced by overhead reimbursements and capitalized G&A. Overhead reimbursements, which decrease overall G&A expense, decreased in 2009 as compared to 2008. Capitalized G&A costs for the first half of 2009 were lower at $1.3 million as compared to $2.1 million for the comparable prior year period. G&A expense on a unit-of-production basis for the six months ended June 30, 2009 increased to $1.56 per Mcfe as compared to $0.95 per Mcfe for the comparable 2008 period. G&A, excluding non-cash share-based compensation costs and bad debt expense, for the six months ended June 30, 2009 also increased due to lower production volumes, averaging $1.46 per Mcfe as compared to $0.81 per Mcfe for the comparable 2008 period.

Other expense, net - During the six months ended June 30, 2009, other income and expense in total was slightly lower than the same period of 2008. We recorded lower interest income in the first half of 2009 as compared to the first half of 2008. For the first half of 2009, 8% of our gross interest expense was capitalized, as compared to 18% in the same period of 2008. We calculate the amount of interest we can capitalize based on the comparison of our unproved property costs and our weighted average debt balance. Gross interest expense in 2008 was higher than 2009 due to higher outstanding debt balances. Although average debt balances outstanding in 2008 were higher than in 2009, the interest rates were lower in 2009 which partially offset the increase in total gross interest.

	For the Six Months Ended June 30,
	2009			2008
	(in thousands)
Gross interest expense	$	5,784		$	7,898
Less: capitalized interest	(472		)	(1,390		)
Interest expense, net	$	5,312		$	6,508

Weighted average debt	$	235,271		$	250,319

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We also recorded amortization of deferred loan costs related to our Revolving Facility during the six months ended June 30, 2009 and 2008. The costs in 2009 were higher than 2008 due to the acceleration of amortization of those capitalized costs resulting from the change in maturity date of the Revolving Facility. During the six months ended June 30, 2008, we recorded a gain on ARO settlements of approximately $9,400.

Income tax expense - We did not record a tax benefit for the six months ended June 30, 2009. We fully provided for additions to our deferred tax asset with a valuation allowance during the period. During the six months ended June 30, 2008, we recorded an income tax benefit of $24.8 million with no valuation allowance.

Preferred stock dividends — Our Board of Directors declared dividends on our 5.75% Series A cumulative convertible perpetual preferred stock in March and June 2008 and none in 2009.

Loss per share - For the first half of 2009 and 2008, we reported a loss per share. In 2009 the loss per share was primarily the result of the $78.3 million impairment of oil and natural gas properties and declines in our oil and natural sales revenue both as a result of decreased oil and natural gas prices. In 2008 the loss per share was primarily the result of unrealized derivative losses of approximately $67.3 million. Basic weighted average shares outstanding for the six months ended June 30, 2009 were comparable to the prior year. We excluded approximately 8.7 million shares of if-converted common stock attributable to our 5.75% Series A cumulative convertible perpetual preferred stock which, when converted, have an anti-dilutive effect and, therefore, are not included in the calculation of diluted earnings per share for the six months ended June 30, 2009 or 2008.

Liquidity and Capital Resources

Historically, our primary ongoing source of capital was the cash flow generated from our operating activities supplemented by borrowings under our Revolving Facility. We currently do not have any available borrowing capacity under our Revolving Facility (see “Revolving Facility” below for additional discussion) and all remaining principal, fees and interest amounts under our Revolving Facility are due and payable on August 31, 2009 to our lenders. Net cash generated from operating activities is a function of production volumes and commodity prices, both of which are inherently volatile and unpredictable, as well as operating efficiency and costs. Our business, as with other extractive businesses, is a depleting one in which each gas equivalent unit produced must be replaced or our asset base and capacity to generate revenues in the future will shrink. Less predictable than production declines from our proved reserves is the impact of constantly changing oil and natural gas prices on cash flows. 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 natural gas prices, industry conditions, availability and cost of goods and services and the extent to which oil and natural gas properties are acquired. In 2009, our capital expenditures have been and will continue to be impacted by our liquidity issues and the impending maturity of our Revolving Facility on August 31, 2009, as well as the Amended Consent and subsequent Amendments which impose significant constraints on our capital expenditures.

Our primary cash requirements are for exploration, development and acquisition of oil and natural gas properties, payment of any preferred stock dividends when and if declared by our Board of Directors, payment of any derivative loss settlements when and if they occur, and the repayment of principal and interest on outstanding debt (including the Deficiency under our Revolving Facility). We have historically attempted to fund our exploration and development activities primarily through internally generated cash flows and budget capital expenditures based largely on projected cash flows, however we do not anticipate that our cash flows will be sufficient to fund our primary cash requirements. We routinely adjust capital expenditures in response to

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changes in oil and natural gas prices, drilling and acquisition costs, and cash flow. We typically have funded acquisitions from borrowings under our credit facilities, cash flow from operations and sales of common stock and preferred stock, though we do not anticipate making any acquisitions in the foreseeable future.

Significant changes to working capital affects our liquidity in the short term. Since December 31, 2008 and continuing as of June 30, 2009, our outstanding debt was classified as current due to the various amendments in the maturity date of our Revolving Facility. As provided by Amendment No. 8 (see “Revolving Facility” below for additional discussion) the current maturity date of the revolving Facility is August 31, 2009. Our derivative instrument asset is indicative of potential future cash settlement inflows on our outstanding oil and natural gas derivative positions, which are scheduled to settle in future months. The fair market value represents the potential settlement for those contracts if the market prices remain unchanged. Should commodity prices increase or decrease, the fair value of those outstanding contracts would also change. When our derivatives result in cash settlement outflows, we receive higher cash inflows on the sale of our physical production at those higher market prices, thus providing us with funds to cover at least a portion of any derivative payments that may come due in the future.

We have historically used our credit facilities to supplement any deficiencies between operating cash flow and capital expenditures. We have also used proceeds of asset divestitures to supplement these deficiencies and reduce outstanding debt. Our outstanding debt balance on August 4, 2009 was $226.5 million.

Although we have used proceeds from private and public offerings of our stock to fund certain acquisition activities in the past, we typically do not rely on proceeds from the exercise of warrants and stock options to sustain our business, as the timing of their exercise is unpredictable.

As a result of the strategic alternatives process we began in late 2007, we reduced our planned capital spending for 2008 as compared to previous years. The recent worldwide financial and credit crisis has reduced the availability of liquidity and credit worldwide, and the recent substantial declines in worldwide equity markets, including our stock prices, make it more difficult to effectively raise capital through equity issuances. Additionally, prices for oil and natural gas declined materially during the fourth quarter of 2008, and natural gas prices continued to decline during the first half of 2009. A continued or extended decline in oil or natural gas prices will have a material adverse effect on our financial position, results of operations, cash flows and access to capital and on the quantities of oil and natural gas reserves that we can economically produce.

We had cash and cash equivalents at June 30, 2009 of $15.7 million consisting primarily of short-term money market investments, as compared to $8.5 million at December 31, 2008. Our working capital deficit was $201.1 million at June 30, 2009, as compared to a working capital deficit of $203.3 million at December 31, 2008. At June 30, 2009 and December 31, 2008, we classified all of our outstanding debt as current due to the various amendments in the maturity date of the Revolving Facility. Our sources and uses of cash were as follows:

	For the Six Months Ended June 30,
	2009			2008
	(in thousands)
Net Cash Provided By Operating Activities	$	19,847		$	53,440

Net Cash Used In Investing Activities	(7,629		)	(24,015		)

Net Cash Used In Financing Activities	(5,000		)	(24,133		)

Net Cash Provided By Operating Activities - The decrease in cash flows provided by operating activities for the first half of 2009 as compared to the same period in 2008 is primarily a result of a decrease in production revenue, partially offset by a decrease in cash costs such as severance taxes and oil and natural gas operating expenses. Changes in working capital increased total cash flows by $5.5 million in the first half of 2009 as compared to $4.1 million in the same period of 2008.

Net Cash Used In Investing Activities - We have historically reinvested a substantial portion of our cash flows in our drilling, acquisition, land and geophysical activities. We are operating under a limited capital

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investment program and spent approximately $9.2 million during the first half of 2009, including $2.4 million on our drilling and operating program. We drilled 4 wells in the first quarter of 2009, three of which were apparent successes. Leasehold and geological and geophysical activities accounted for expenditures of $6.8 million through June 30, 2009. During the first six months of 2008, we spent $33.9 million on our drilling and operating program. We drilled 15 wells in the first half of 2008, 14 of which were apparent successes. Leasehold and geological and geophysical activities accounted for expenditures of $2.7 million through June 30, 2008. There were also minimal capital expenditures associated with computer hardware, office equipment and other miscellaneous capital charges. During the six months ended June 30, 2009, proceeds from the sale of certain non-core properties in Texas to various buyers totaled approximately $0.3 million. In the same period last year, proceeds from the sale of certain non-core properties in Texas and a pipeline to various buyers totaled approximately $18.2 million.

Due to the overhedged position in 2008, cash settlements related to the overhedged position are reflected in investing activities because they do not apply to operating revenues and are similar in nature to an investment. Approximately 42% of our oil settlements and 17% of our natural gas settlements are represented by the $6.2 million of speculative settlements in this section of the statement of cash flows. The remainder is located in net cash provided by operating activities. There was no overhedged position in the first half of 2009.

Net Cash Used In Financing Activities - During the six months ended June 30, 2009, we repaid $5.0 million under our Revolving Facility (as defined below). In the comparable period of 2008, we repaid $20.0 million using proceeds from our asset sales. We also paid quarterly dividends on our preferred stock in January and April 2008, but none in 2009.

Revolving Facility

On January 30, 2007, we entered into the Revolving Facility with the Lenders, in favor of the Company and certain of its wholly-owned subsidiaries in an amount equal to $750 million. The Revolving Facility has a letter of credit sub-limit of $20 million. The Revolving Facility was scheduled to mature on January 31, 2011. At June 30, 2009, borrowings under the Revolving Facility bore interest at Prime plus an applicable margin of 2.50%. At June 30, 2009, the interest rate applied to our outstanding borrowings was 5.75%. As of June 30, 2009, we had $234 million in total borrowings outstanding under the Revolving Facility. During January 2009, the Lenders established a new borrowing base of $125 million under the Revolving Facility resulting in a borrowing base deficiency of $114 million.

· On February 9, 2009, we entered into a Consent and Agreement (the “February Consent”) among us and the Lenders under the Revolving Facility deferring the payment date of the first $19 million installment until March 10, 2009, and extending the due date for each subsequent installment by one month with the last of the six installment payments to be due on August 10, 2009. In connection with the February Consent, we prepaid $5.0 million of our outstanding advances under the Revolving Facility, in two equal installments of $2.5 million on February 9, 2009 and February 23, 2009, with each of these prepayments applied on a pro rata basis to reduce the six remaining $19 million deficiency payments.

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Revolving Facility to be due and payable on June 30, 2009, (2) that it would be an event of default (i) if we failed to have executed and delivered on or before May 15, 2009 at least one of the following (a) a commitment letter from a lender or group of lenders reasonably satisfactory to our Lenders providing for the provision by such lender or group of lenders of a credit facility in an amount sufficient to repay all of our obligations under the Revolving Facility on or before June 30, 2009, (b) a merger agreement or similar agreement involving us as part of a transaction that results in the repayment of our obligations under the Revolving Facility on or before June 30, 2009, and (c) a purchase and sale agreement with a buyer or group of buyers reasonably acceptable to our Lenders providing for a sale transaction by us that results in the repayment of all of our obligations under the Revolving Facility on or before June 30, 2009, or (ii) if we were in default under or our hedging arrangements have been terminated or cease to be effective without the prior written consent of our Lenders, (3) that our advances under the Revolving Facility would bear interest at a rate equal to the greater of (a) the reference rate publicly announced by Union Bank of California, N.A. for such day, (b) the Federal Funds Rate in effect on such day plus 0.50% and (c) a rate determined by the Administrative Agent to be the Daily One-Month LIBOR (as defined in the Revolving Facility), in each case plus 2.5% or, during the continuation of an event of default, plus 4.5% (resulting in an effective interest rate of approximately 5.75%), (4) for limitations on the making of capital expenditures and certain investments, and (5) for the elimination of the current ratio, leverage ratio and interest coverage ratio covenant requirements. The Amended Consent also eliminated the six $19 million deficiency payments which were contemplated by the February Consent and the March Consent.

· On June 30, 2009, we entered into Amendment No. 7 (“Amendment No. 7”) which provided for, among other things, (1) changing the maturity date of the Revolving Facility from June 30, 2009 to July 31, 2009, (2) the Company’s agreement to make a prepayment of interest of approximately $1,142,753.42 representing the amount anticipated to be owing in respect of the interest payment due and payable on July 31, 2009 and (3) the Company’s agreement to make a prepayment of the advances under the Revolving Facility in the amount of $7.5 million with such prepayment to be made on or before July 10, 2009. The Company paid the July interest of approximately $1.1 million on July 1, 2009 and also paid $7.5 million on July 10, 2009.

· On July 31, 2009 we entered into Amendment No. 8 (“Amendment No. 8”) which changed the maturity date of the Company’s Revolving Facility from July 31, 2009 to August 31, 2009.

If we breach any of the provisions of the Amended Consent or the Revolving Facility, as amended, our Lenders thereto will be entitled to declare an event of default, at which point the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, would become immediately due and payable. In any event, the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, will be payable on August 31, 2009 unless earlier paid or a further extension with respect to payment is negotiated with our Lenders. Our Lenders may take action to enforce their rights with respect to the outstanding obligations under the Revolving

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Facility. Because substantially all of our assets are pledged as collateral under the Revolving Facility, if our Lenders declare an event of default, they would be entitled to foreclose on and take possession of our assets. In such an event, we may be forced to liquidate or to otherwise seek protection under Chapter 11 of the U.S. Bankruptcy Code. Such action in itself would constitute an event of default under the terms of the Revolving Facility. These matters, as well as the other risk factors related to our liquidity and financial position raise substantial doubt as to our ability to continue as a going concern. With respect to our compliance with the Amended Consent, there can be no assurance that we will be able to further negotiate the terms of the Amended Consent or negotiate a further restructuring of the related indebtedness or that we will be able to make any required payments when they become due. Moreover, there can be no assurance that we will be successful in our efforts to comply with the terms of the Amended Consent, including our ongoing efforts to evaluate and assess our various financial and strategic alternatives (which may include the sale of some or all of our assets, a merger or other business combination involving the Company, or the restructuring or recapitalization of the Company). If such efforts are not successful, we may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code, which would constitute an event of default under the Revolving Facility. See Item 1A. RISK FACTORS.

The Revolving 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 Revolving Facility restricts common stock dividends and certain distributions of cash or properties and certain liens but no longer contains any financial covenants.

The Revolving Facility includes other covenants and events of default that are customary for similar facilities. It is an event of default under the Revolving Facility if we undergo a change of control. “Change of control,” as defined in the Revolving Facility, means any of the following events: (a) any “person” or “group” (within the meaning of Section 13(d) or 14(d) of the Exchange Act) has become, directly or indirectly, the “beneficial owner” (as defined in Rules 13d-3 and 13d-5 under the Exchange Act, except that a person shall be deemed to have “beneficial ownership” of all such shares that any such person has the right to acquire, whether such right is exercisable immediately or only after the passage of time, by way of merger, consolidation or otherwise), of a majority or more of our common stock on a fully-diluted basis, after giving effect to the conversion and exercise of all of our outstanding warrants, options and other securities (whether or not such securities are then currently convertible or exercisable), (b) during any period of two consecutive calendar quarters, individuals who at the beginning of such period were members of our Board of Directors cease for any reason to constitute a majority of the directors then in office unless (i) such new directors were elected by a majority of our directors who constituted the Board of Directors at the beginning of such period (or by directors so elected) or (ii) the reason for such directors failing to constitute a majority is a result of retirement by directors due to age, death or disability, or (c) we cease to own directly or indirectly all of the equity interests of each of our subsidiaries.

Shelf Registration Statement & Offerings

In the third quarter of 2007, the SEC declared effective our registration statement filed with the SEC that registered securities of up to $500 million of any combination of debt securities, preferred stock, common stock, warrants for debt securities or equity securities of the Company and guarantees of debt securities by our subsidiaries. Net proceeds, terms and pricing of the offering of securities issued under the shelf registration statement will be determined at the time of the offerings. The shelf registration statement does not provide assurance that we will or could sell any such securities. 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. However, because the aggregate market value of our outstanding common stock is less than $75 million, the type and amount of any securities offering under the registration statement may be limited.

Convertible Preferred Stock

We completed the public offering of 2,875,000 shares of 5.75% Series A cumulative convertible perpetual preferred stock (“Convertible Preferred Stock”) in January 2007.

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Dividends . The Convertible Preferred Stock accumulates dividends at a rate of $2.875 for each share of Convertible Preferred Stock per year. Dividends are cumulative from the date of first issuance and, to the extent payment of dividends is not prohibited by our debt agreements, assets are legally available to pay dividends and our Board of Directors or an authorized committee of our board declares a dividend payable, we will pay dividends in cash, every quarter. The first payment was made on April 15, 2007 and we continued to make quarterly dividends payments through October 15, 2008. The Board did not declare a dividend in the fourth quarter of 2008, first quarter of 2009 or second quarter of 2009 due to our current lack of liquidity. Cumulative dividends in arrears at June 30, 2009 amounted to $5.9 million.

No dividends or other distributions (other than a dividend payable solely in shares of a like or junior ranking) may be paid or set apart for payment upon any shares ranking equally with the Convertible Preferred Stock (“parity shares”) or shares ranking junior to the Convertible Preferred Stock (“junior shares”), nor may any parity shares or junior shares be redeemed or acquired for any consideration by us (except by conversion into or exchange for shares of a like or junior ranking) unless all accumulated and unpaid dividends have been paid or funds therefor have been set apart on the Convertible Preferred Stock and any parity shares.

Liquidation preference . In the event of our voluntary or involuntary liquidation, winding-up or dissolution, each holder of Convertible Preferred Stock will be entitled to receive and to be paid out of our assets available for distribution to our stockholders, before any payment or distribution is made to holders of junior stock (including common stock), but after any distribution on any of our indebtedness or senior stock, a liquidation preference in the amount of $50.00 per share of the Convertible Preferred Stock, plus accumulated and unpaid dividends on the shares to the date fixed for liquidation, winding-up or dissolution.

Ranking . Our Convertible Preferred Stock ranks:

· senior to all of the shares of our common stock and to all of our other capital stock issued in the future unless the terms of such capital stock expressly provide that it ranks senior to, or on a parity with, shares of our Convertible Preferred Stock;

· on a parity with all of our other capital stock issued in the future, the terms of which expressly provide that it will rank on a parity with the shares of our Convertible Preferred Stock; and

· junior to all of our existing and future debt obligations and to all shares of our capital stock issued in the future, the terms of which expressly provide that such shares will rank senior to the shares of our Convertible Preferred Stock.

Mandatory conversion . On or after January 20, 2010, we may, at our option, cause shares of our Convertible Preferred Stock to be automatically converted to shares of our common stock at the applicable conversion rate, but only if the closing sale price of our common stock for 20 trading days within a period of 30 consecutive trading days ending on the trading day immediately preceding the date we give the conversion notice equals or exceeds 130% of the conversion price in effect on each such trading day.

Optional redemption . If fewer than 15% of the shares of Convertible Preferred Stock issued in the Convertible Preferred Stock offering (including any additional shares issued pursuant to the underwriters’ over-allotment option) are outstanding, we may, at any time on or after January 20, 2010, at our option, redeem for cash all such Convertible Preferred Stock at a redemption price equal to the liquidation preference of $50.00 plus any accrued and unpaid dividends, if any, on a share of Convertible Preferred Stock to, but excluding, the redemption date, for each share of Convertible Preferred Stock.

Conversion rights . Each share of Convertible Preferred Stock may be converted at any time, at the option of the holder, into approximately 3.0193 shares of our common stock (which is based on an initial conversion price of $16.56 per share of common stock, subject to adjustment) plus cash in lieu of fractional shares, subject to our right to settle all or a portion of any such conversion in cash or shares of our common stock. If we elect to settle all or any portion of our conversion obligation in cash, the conversion value and the number of shares of our common stock we will deliver upon conversion (if any) will be based upon a 20 trading day averaging period.

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Upon any conversion, the holder will not receive any cash payment representing accumulated and unpaid dividends on the Convertible Preferred Stock, whether or not in arrears, except in limited circumstances. The conversion rate is equal to $50.00 divided by the conversion price at the time. The conversion price is subject to adjustment upon the occurrence of certain events. The conversion price on the conversion date and the number of shares of our common stock, as applicable, to be delivered upon conversion may be adjusted if certain events occur.

Purchase upon fundamental change . If we become subject to a fundamental change (as defined herein), each holder of shares of Convertible Preferred Stock will have the right to require us to purchase any or all of its shares at a purchase price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends, to the date of the purchase. We will have the option to pay the purchase price in cash, shares of common stock or a combination of cash and shares. Our ability to purchase all or a portion of the Convertible Preferred Stock for cash is subject to our obligation to repay or repurchase any outstanding debt required to be repaid or repurchased in connection with a fundamental change and to any contractual restrictions then contained in our debt.

Conversion in connection with a fundamental change . If a holder elects to convert its shares of our Convertible Preferred Stock in connection with certain fundamental changes, we will in certain circumstances increase the conversion rate for such Convertible Preferred Stock. Upon a conversion in connection with a fundamental change, the holder will be entitled to receive a cash payment for all accumulated and unpaid dividends.

A “fundamental change” will be deemed to have occurred upon the occurrence of any of the following:

1. a “person” or “group” subject to specified exceptions, discloses that the person or group has become the direct or indirect ultimate “beneficial owner” of our common equity representing more than 50% of the voting power of our common equity other than a filing with a disclosure relating to a transaction which complies with the proviso in subsection 2 below;

2. consummation of any share exchange, consolidation or merger of us pursuant to which our common stock will be converted into cash, securities or other property or any sale, lease or other transfer in one transaction or a series of transactions of all or substantially all of the consolidated assets of us and our subsidiaries, taken as a whole, to any person other than one of our subsidiaries; provided, however, that a transaction where the holders of more than 50% of all classes of our common equity immediately prior to the transaction own, directly or indirectly, more than 50% of all classes of common equity of the continuing or surviving corporation or transferee immediately after the event shall not be a fundamental change;

3. we are liquidated or dissolved or holders of our capital stock approve any plan or proposal for our liquidation or dissolution; or

4. our common stock is neither listed on a national securities exchange nor listed nor approved for quotation on an over-the-counter market in the United States.

Voting rights . If we fail to pay dividends for six quarterly dividend periods (whether or not consecutive) or if we fail to pay the purchase price on the purchase date for the Convertible Preferred Stock following a fundamental change, holders of our Convertible Preferred Stock will have voting rights to elect two directors to our board.

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In addition, we may generally not, without the approval of the holders of at least 66 2/3% of the shares of our Convertible Preferred Stock then outstanding:

· amend our restated certificate of incorporation, as amended, by merger or otherwise, if the amendment would alter or change the powers, preferences, privileges or rights of the holders of shares of our Convertible Preferred Stock so as to adversely affect them;

· issue, authorize or increase the authorized amount of, or issue or authorize any obligation or security convertible into or evidencing a right to purchase, any senior stock; or

· reclassify any of our authorized stock into any senior stock of any class, or any obligation or security convertible into or evidencing a right to purchase any senior stock.

Off Balance Sheet Arrangements

We currently do not have any off balance sheet arrangements.

Fair Value Measurements

Effective January 1, 2008, we partially adopted SFAS No. 157, Fair Value Measurements which provides a common definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements, but does not require any new fair value measurements. The partial adoption of SFAS No. 157 had no impact on our financial statements, but it did result in additional required disclosures as set forth in Note 11 to our consolidated financial statements. In February 2008, the FASB issued FSP FAS 157-2, Effective Date of FASB Statement No. 157 , which delayed the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Accordingly, we applied the provisions of SFAS No. 157 to our AROs on January 1, 2009.

SFAS No. 157 defines fair value as the price that would be received to sell an asset or transfer a liability in an orderly transaction between market participants at the measurement date. Currently the only fair value measurements we utilize are related to our AROs and derivative instruments. While our derivative instruments are executed in liquid markets where price transparency exists, we are not involved in the monthly calculation of fair value. We utilize valuations provided by our counterparties, which include inputs such as commodity exchange prices on the NYMEX, over-the-counter quotations, volatility, historical correlations of pricing data and LIBOR and, in the case of collars and floors, the time value of options, and other liquid money market instrument rates. Our counterparties utilize internally developed basis curves that incorporate observable and unobservable market data. Although we believe these valuations are the best estimates of the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ from these estimates, and the differences could be material.

SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value based on observable and unobservable data and categorizes the inputs into three levels, with the highest priority given to Level 1 and the lowest priority given to Level 3. The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

· Level 1 — Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities.

· Level 2 — Significant observable pricing inputs other than quoted prices included within Level 1 that are either directly or indirectly observable as of the reporting date. Essentially, inputs that are derived principally from or corroborated by observable market data.

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· Level 3 — Generally, inputs are unobservable, developed based on the best information available and reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date.

Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. Currently we have categorized derivative instruments’ fair value measurements and our AROs as Level 3. As interpretations of SFAS No. 157 evolve, our classification of certain instruments within the hierarchy may be revised. See “Critical Accounting Policies and Estimates — Derivative and Hedging Activities” above, “Risk Management Activities” below and Note 11 to our consolidated financial statements for additional discussion of our derivative instruments.

Risk Management Activities

We utilize price-risk management transactions (e.g., swaps, collars and floors) for a portion of our expected oil and natural gas production to seek to reduce exposure from the volatility of oil and natural gas prices and also to achieve a more predictable cash flow. While the use of these arrangements is intended to reduce our potential exposure to significant commodity price declines, they may limit our ability to benefit from increases in the price of oil and natural gas. Our arrangements, to the extent we enter into any, are intended to apply to only a portion of our expected production and thereby provide only partial price protection against declines in oil and natural gas prices. None of these instruments are, at the time of their execution, intended to be used for trading or speculative purposes, but a portion of our 2008 instruments was subsequently deemed as such because of the decrease in our 2008 production. These price-risk management transactions are generally placed with major financial institutions that we believe are financially stable; however, in light of the recent global financial crisis, there can be no assurance of the foregoing. In the event any such counterparty fails to perform, our financial results could be adversely affected and we could incur losses and our liquidity could be negatively impacted. None of our derivative contracts contain collateral posting requirements; however, the counterparty to our 2009 positions is a member of the lending group of our Revolving Facility, and certain events of default under our Revolving Facility may result in a cross default of derivative instruments with such party. In addition, our counterparty is entitled to terminate the derivative contracts in the event that the fair market value of the derivative contracts (currently valued at approximately $12.7 million as of June 30, 2009) falls to less than $1.5 million (i.e. the approximate amount that our counterparty would owe us upon termination of the derivative contracts following the decline of the derivative fair market value from the approximate $12.7 million as of June 30, 2009 to less than $1.5 million at any time thereafter). In the event of a termination of the derivative contracts by our counterparty under these circumstances, there can be no assurance that this counterparty would actually remit the funds owed to us as opposed to attempting to apply such funds as an offset to our indebtedness under the Revolving Facility of which they are a lender. However, to the extent that any decrease in the fair market value of the derivative contracts is driven by higher commodity prices, such rising commodity prices should result in some benefit to our expected oil and natural gas sales revenue. On an annual 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 monitors our price-risk management policies and trades on a monthly basis. However, due to the ongoing financial and strategic alternatives process the Company has not entered into any new derivative contracts in recent months and does not expect to for the foreseeable future.

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 (as amended). These derivative instruments are intended to hedge our price risk and may be considered hedges for economic purposes. There are two types of accounting treatments for derivatives, (i) mark-to-market accounting and (ii) cash flow hedge accounting. For a discussion of these accounting treatments, see Note 10 to our consolidated financial statements. We currently apply mark-to-market accounting treatment to all of our derivative contracts. All derivatives are recorded on the balance sheet at fair value and the changes in fair value are presented in total revenue on the statement of operations. The cash flows resulting from settlement of derivative transactions which relate to economically hedging our physical production volumes are classified in operating activities on the statement of cash flows and the cash flows resulting from settlement of derivative transactions considered “overhedged” positions are classified in investing activities on the statement of cash flows. The following table provides additional information regarding our various derivative transactions that were recorded at fair value on the balance sheet as of June 30, 2009.

	(in thousands)
Fair value of contracts outstanding at December 31, 2008	$	15,407
Contracts realized or otherwise settled during the period	13,876
Fair value at June 30, 2009 of new contracts entered into during 2009:
Asset	—
Liability	—
Changes in fair value attributable to changes in valuation techniques and assumptions	—
Other changes in fair value	(16,574		)
Fair value of contracts outstanding at June 30, 2009	$	12,709

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The following table details the fair value of our commodity-based derivative contracts by year of maturity and valuation methodology as of June 30, 2009.

	Fair Value of Contracts at June 30, 2009
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
	(in thousands)
Prices actively quoted:	$	—	$	—	$	—	$	—	$	—
Prices provided by other external sources:
Asset	12,709		—		—		—		12,709
Liability	—		—		—		—		—
Prices based on models and other valuation methods:	—		—		—		—		—
Total	$	12,709	$	—	$	—	$	—	$	12,709

Tax Matters

At June 30, 2009, we had cumulative net operating loss carryforwards (“NOLs”) for federal and state income tax purposes of approximately $153.2 million and $5.7 million, respectively, without consideration of valuation allowances. The federal and state NOL carryforwards will expire in varying amounts between 2009 and 2028. In addition to the deferred tax assets associated with NOLs discussed above, we have additional net deferred tax assets of approximately $85.2 million related to both federal and state tax positions.

In recording deferred income tax assets, we consider whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. We consider the scheduled reversal of deferred income tax liabilities and projected future taxable income for this determination. We believe that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to the historical evidence, and in light of the current market situation and the uncertainty surrounding our Revolving Facility, the related Amended Consent and subsequent Amendments, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and therefore established a full valuation allowance to reduce our net deferred tax asset to zero at June 30, 2009 and December 31, 2008. We will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods. If we achieve profitable operations in the future, we may reverse a portion of the valuation allowance in an amount at least sufficient to eliminate any tax provision in that period. The valuation allowance has no impact on our NOL position for tax purposes, and if we generate taxable income in future periods, we will be able to use our NOLs to offset taxes due at that time.

Our ability to utilize federal and state NOL carryforwards in cases where the NOL was acquired in a reorganization are subject to limitations under Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”). There will be further limitations if we undergo another majority ownership change as defined by Section 382.

We would undergo a majority ownership change if, among other things, the stockholders who own or have owned, directly or indirectly, five percent or more of our common stock or are otherwise treated as five percent stockholders under Section 382 and the regulations promulgated thereunder, increase their aggregate percentage

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ownership of our stock by more than 50 percentage points over the lowest percentage of stock owned by these stockholders at any time during the testing period, which is generally the three-year period preceding the potential ownership change. In the event of a majority ownership change, Section 382 imposes an annual limitation on the amount of taxable income a corporation may offset with the NOL carryforwards. Any unused annual limitation may be carried over to later years until the applicable expiration of the respective NOL carryforwards. The amount of the limitation may, under certain circumstances, be increased by built-in gains held by us at the time of the change that are recognized in the five-year period after the change. Any built-in losses on assets held subsequent to a merger are subject to the limitation. If we were to undergo a majority ownership change, we will likely be required to record a reserve for some or all of the asset that may be recorded on our balance sheet at that time. During 2007, we believe that there was a change of ownership pursuant to Section 382 as a result of the concurrent public offerings of our common and preferred stock that occurred in January 2007. The 2007 limitation did not result in the requirement to record a reserve. We cannot make assurances that we will not undergo a majority ownership change in the future because an ownership change for federal tax purposes can occur based on trades among our existing stockholders. Whether we undergo a majority ownership change may be a matter beyond our control. Further, in light of the ongoing financial and strategic alternatives process, we cannot provide any assurance that a potential sale or merger will not reduce the availability of our NOL carryforward and other federal income tax attributes, which may be significantly limited or possibly eliminated.

FASB Interpretation No. 48 (“FIN 48”), Accounting for Uncertainty in Income Taxes , provides guidance on recognition and measurement of uncertainties in income taxes. FIN 48 requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. See Notes 3 and 8 to our consolidated financial statements. We have recorded our FIN 48 liability of approximately $0.1 million under long term liabilities on the balance sheet and there has been no change since December 31, 2008.

Recently Issued Accounting Pronouncements (Not Yet Adopted)

In December 2008, the SEC issued the final rule, “Modernization of Oil and Gas Reporting ,” which adopts revisions to the SEC’s oil and natural gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. Early adoption of the new rules is prohibited. The new rules are intended to provide investors with a more meaningful and comprehensive understanding of oil and natural gas reserves to help investors evaluate their investments in oil and natural gas companies. The new rules are also designed to modernize the oil and natural gas disclosure requirements to align them with current practices and changes in technology. The new rules include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves and permitting disclosure of probable and possible reserves. We are currently evaluating the potential impact of these rules. The SEC is discussing the rules with the FASB staff to align FASB accounting standards with the new SEC rules. These discussions may delay the required compliance date. Absent any change in the effective date, we will begin complying with the disclosure requirements in our annual report on Form 10-K for the year ended December 31, 2009.

In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No. 46(R) , which amends the consolidation guidance applicable to variable interest entities. The amendments significantly reduce the previously required quantitative consolidation analysis, and require ongoing reassessments of whether the Company is the primary beneficiary of a variable interest entity. SFAS No. 167 also requires enhanced disclosures about an enterprise’s involvement with a variable interest entity. This statement is effective for the beginning of the first annual reporting period beginning after November 15, 2009. The Company does not currently expect the adoption of SFAS No. 167 to impact its consolidated financial statements.

On June 3, 2009, the FASB approved the FASB Accounting Standards Codification™ (“Codification”) as the single source of generally accepted accounting principles in the United States of America (“GAAP”). On June 29, 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards Codification TM and the

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Hierarchy of Generally Accepted Accounting Principles . SFAS No. 168 establishes the Codification to become the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. Codification supersedes all existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification becomes non-authoritative. Following SFAS No. 168, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to: (a) update the Codification; (b) provide background information about the guidance; and (c) provide the bases for conclusions on the change(s) in the Codification. The content of the Codification carries the same level of authority. The GAAP hierarchy will be modified to include only two levels of GAAP: authoritative and non-authoritative. SFAS No.168 and the Codification are effective for financial statements issued for interim and annual periods ending after September 15, 2009. This means that a calendar year-end public entity should follow the guidelines in the Codification beginning with its third quarter starting on July 1, 2009. We adopted Codification on July 1, 2009 which will provide for changes in disclosures on our Quarterly Report on Form 10-Q for the period ended September 30, 2009 but no impact to our financial position, results of operations or cash flows.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk from changes in interest rates and commodity prices. We use a Revolving Facility, which has a floating interest rate. We are not subject to fair value risk resulting from changes in our floating interest rates. The use of floating rate debt instruments provides a benefit due to downward interest rate movements but does not limit us to exposure from future increases in interest rates. Based on the June 30, 2009 outstanding borrowings and an interest rate of 5.75%, a 10% change in these interest rates would result in an increase or decrease in interest expense of approximately $1.3 million on an annual basis.

The debt and equity markets have recently exhibited adverse conditions. The unprecedented volatility and upheaval in the capital markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets. We believe the recent events in the global markets had significant impact on our recent borrowing base redetermination that resulted in our significant borrowing base deficiency. The continued credit crisis and related turmoil in the global financial system and economic recession in the U.S. create financial challenges if conditions do not improve and will affect our ability to access credit markets. We will continue to monitor our liquidity and the capital markets as we continue to assess our financial and strategic alternatives.

As of December 31, 2008 and June 30, 2009, our outstanding debt was classified as current due to the amendment in the maturity date of our Revolving Facility to June 30, 2009 as provided by the Amended Consent and August 31, 2009 as provided by Amendment No. 8, respectively.

In the normal course of business, we enter into derivative transactions, including commodity price collars, swaps and floors, to mitigate our exposure to commodity price movements. At the time of their execution, they are not intended for trading or speculative purposes. While the use of these arrangements may limit the benefit to us of increases in the price of oil and natural gas, it also limits the downside risk of adverse price movements. During 2007, we put in place several natural gas and crude oil derivatives to hedge our expected 2009 production to achieve a more predictable cash flow. Please refer to Note 10 to our consolidated financial statements for a discussion of these contracts. The following is a list of contracts outstanding at June 30, 2009:

Transaction
Date

Transaction
Type

Beginning

Ending

Price
Per Unit

Volumes Per
Day

Fair Value
Outstanding as of
June 30, 2009

(in thousands)

Natural Gas (1):

04/07

Collar

01/01/09

12/31/09

$7.75-$10.00

10,000 MMBtu

6,247

10/07

Collar

01/01/09

12/31/09

$7.75-$10.08

10,000 MMBtu

6,248

Crude Oil (2):

10/07

Collar

01/01/09

12/31/09

$70.00-$93.55

300 Bbl

214

12,709

(1) Our natural gas contracts were entered into on a per MMBtu delivered price basis, using the NYMEX Natural Gas Index. Mark-to-market accounting treatment is applied to these contracts and the change in fair value is reflected in total revenue.

(2) Our crude oil contract was entered into on a per barrel delivered price basis, using the West Texas Intermediate Light Sweet Crude Oil Index. Mark-to-market accounting treatment is applied to this contract and the change in fair value is reflected in total revenue.

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At June 30, 2009, the fair value of the outstanding derivatives was a net asset of approximately $12.7 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 derivative instruments to increase or decrease by approximately $1.2 million.

ITEM 4. CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2009 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

There has been no change in our internal controls over financial reporting that occurred during the three months ended June 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

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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 our business. While the outcome of lawsuits cannot be predicted with certainty, we are not currently a party to any proceeding that we believe, if determined in a manner adverse to us, could have a material adverse effect on our financial condition, results of operations or cash flows, except as set forth below.

David Blake, et al. v. Edge Petroleum Corporation — On September 19, 2005, David Blake and David Blake, Trustee of the David and Nita Blake 1992 Children’s Trust, filed suit against us in state district court in Goliad County, Texas alleging breach of contract for failure and refusal to transfer overriding royalty interests to plaintiffs in several leases in the Nita and Austin prospects in Goliad County, Texas and failure and refusal to pay monies to Blake pursuant to such overriding royalty interests for wells completed on the leases. The plaintiffs seek relief of (1) specific performance of the alleged agreement, including granting of overriding royalty interests by us to Blake; (2) monetary damages for failure to grant the overriding royalty interests; (3) exemplary damages for his claims of business disparagement and slander; (4) monetary damages for tortious interference; and (5) attorneys’ fees and court costs. Venue of the case was transferred to Harris County, Texas by agreement of the litigants. Our subsidiaries, Edge Petroleum Exploration Company, Edge Petroleum Operating Company and Edge Petroleum Production Company, were also added as defendants. We filed a counterclaim against plaintiff and joined various related entities that are controlled by Blake, seeking lease interests in which we contend we have been wrongfully denied participation and also claim that proprietary information was misappropriated. The parties have moved for summary judgment on each other’s claims and counterclaims, which the trial court has denied as to both sides. In November 2007, we filed a separate motion for summary judgment based on the statute of frauds and; the court has not yet ruled on this separate motion. In June 2008, the Plaintiffs filed a Sixth Amended Petition conditionally adding claims for certain prospects that had been previously settled by means of a Compromise and Settlement Agreement (the “Settlement Agreement”), entered in settlement of prior litigation among some of the parties, but only to the extent that rescission of the prior Settlement Agreement was being sought by us. We are not seeking rescission of the prior Settlement Agreement and responded accordingly in its Fourth Amended Original Counterclaim and Claims Against Additional Parties filed on October 16, 2008. On October 17, 2008, the Plaintiffs filed their Seventh Amended Petition adding a claim for breach of the Settlement Agreement. In December 2008, one of the Blake counter-defendants filed a motion to arbitrate, which motion has not been heard by the court. We have responded and will continue to respond aggressively to this lawsuit, and believe we have meritorious defenses and counterclaims.

Mary Jane Carol Trahan Champagne, et al. v. Edge Petroleum Exploration Company, et al. — On September 19, 2008 we were sued in state district court in Vermilion Parish, Louisiana by Mary Jane Trahan, Carol Trahan Champagne and 29 other plaintiffs alleging breach of obligations under mineral leases in Vermilion Parish regarding the Trahan No. 1 well and the Trahan No. 3 well (MT RC SUB reservoir). Plaintiffs are seeking unspecified damages for lost revenue, lost royalties and devaluation of property interest sustained as a result of the defendants’ alleged negligent and improper drilling operations on the Trahan No. 1 well and the Trahan No. 3 well, including alleged failure to prevent underground water from flooding and destroying plaintiffs’ portion of the reservoir beneath plaintiffs’ property. Plaintiffs also allege defendants failed to “block squeeze” sections of the Trahan No. 3 well as would a prudent operator. This lawsuit, previously removed from the state court to the federal district court for the Western District of Louisiana, Lafayette Division, has been remanded to state court. Our insurance carrier has retained counsel to represent us in this matter. We filed certain peremptory challenges and exceptions to the Plaintiffs’ petition, including prematurity, no cause of action and prescription. Except for the prescription challenge, these motions were overruled by the court in May, 2009. We have not established a reserve with respect to this claim and it is not possible to determine what, if any, its ultimate exposure might be in this matter. We intend to vigorously defend ourselves in this lawsuit.

John Lemke, et al. v. Edge Petroleum Corporation - In October 2008, we were sued in state district court in Harris County, Texas over an alleged contract to receive a royalty in certain areas in South Louisiana.

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We, along with the Plaintiffs, settled the dispute by agreement pursuant to which we paid the Plaintiffs $17,500 in return for a full release of all claims and a dismissal of the lawsuit.

Lara Energy, Inc. v. Edge Petroleum Corporation - In June 2009, we were sued in state district court in Harris County, Texas by a working interest co-owner in the Chapman Ranch prospect located in Nueces County, Texas. Plaintiff alleges various theories of causes of action, including breach of contract, breach of duty of good faith and fair dealing, negligent misrepresentation, improper acquisition of leases and seismic data, fraudulent inducement and other causes of action. We believe we have done nothing wrong and have honored the contracts with the Plaintiff that govern operations in the Chapman Ranch prospect. We have filed an answer and intend to vigorously defend ourselves.

Encinitas Ranch et al v. ExxonMobil Corporation, et al . — This lawsuit was originally filed in state district court in Brooks County, Texas, against ExxonMobil, Chevron USA and other defendants alleging numerous causes of action relating to Plaintiffs’ lands going back several decades, including damage to the surface, improperly abandoned equipment, spills, contamination, trespass, failure to maintain facilities, improper or untimely payment of royalties, breach of express and implied covenants, and various acts of negligence, including an alleged incident regarding a fire that occurred on the ranch in 2008. Plaintiffs amended their petition in May 2008 to name additional defendants, including the Company. The Company has a non-operating interest in the Encinitas Ranch, and has never operated the wells or lease in Brooks County, Texas, covering Plaintiffs’ land. Our liability insurance carrier is providing a defense to this matter under a reservation of rights, and has retained local counsel for us and filed an answer on our behalf. No trial date has been set. We believe we have meritorious defenses to this litigation and intend to vigorously defend ourselves.

Item 1A — Risk Factors

In addition to the other information and risk factors set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our 2008 Annual Report on Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2008 Annual Report on Form 10-K are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

All of our debt obligations under our Revolving Facility are due on or before August 31, 2009. Our attempts to further extend or renegotiate such obligations or to otherwise complete our restructuring efforts (including a sale of some or all of our assets or a recapitalization, merger or business combination involving the Company) may not be successful and we may be required to seek bankruptcy protection under Chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”). Even if these restructuring efforts are successful, we may still be required to seek protection under the Bankruptcy Code to consummate the sale of some or all of our assets or to effect a recapitalization, merger, other business combination or other restructuring strategy involving the Company.

Pursuant to Amendment No. 8 to our Revolving Facility, all of our debt obligations under the Revolving Facility are due on or before August 31, 2009. There can be no assurance that we will be able to further extend or renegotiate the terms of our Revolving Facility or otherwise complete our restructuring efforts (including a sale of some or all of our assets or a recapitalization, merger or business combination involving the Company). Because substantially all of our assets are pledged as collateral under the Revolving Facility, if our lenders declare an event of default, they would be entitled to foreclose on and take possession of our assets. In the event our debt obligations under the Revolving Facility become due and absent a significant restructuring of that indebtedness, we will be unable to make the required payments and in such event we would likely be required to seek protection under the Bankruptcy Code. Moreover, there can be no assurance that we will be successful in our restructuring efforts, including our efforts to sell some or all of our assets or to consummate a recapitalization, merger or other business combination involving the Company. If such efforts are not successful, we may be required to seek protection under the Bankruptcy Code. Even if such efforts are successful, we may still be required to seek protection under the Bankruptcy Code to consummate such a transaction or series of transactions.

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Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise in accordance with the Bankruptcy Code, pre-petition liabilities and post-petition liabilities (including certain fees and interest) must be satisfied in full before stockholders are entitled to receive any distribution or retain any property under a plan of reorganization. Amounts that would need to be satisfied in full before any recovery by our stockholders (including common stockholders and holders of our Convertible Preferred Stock) would include, among other things, approximately $226.5 million in principal plus any accrued interest which is owed under our Revolving Facility. In addition, the holders of our Convertible Preferred Stock have a liquidation preference of $50 per share which, while still being junior to the claims of our debt and other obligations, would need to be satisfied before any proceeds would be received by our common stockholders. The total amount of this liquidation preference is approximately $143.75 million and any recovery for our common stockholders would only be available if the proceeds available in any Bankruptcy Code proceeding exceeded the amount required to repay all of our outstanding indebtedness and other obligations (including trade payables and other unsecured claims) and to also satisfy the $143.75 million Convertible Preferred Stock liquidation preference. Although the Convertible Preferred Stock is entitled to a liquidation preference as discussed above, the holders of the Convertible Preferred Stock would only be entitled to receive a recovery in the event the proceeds available for distribution in any Bankruptcy Code proceeding were in excess of the amount required to repay all of our outstanding indebtedness (including indebtedness under the Revolving Facility) and other obligations (including trade payables and other unsecured claims). The ultimate recovery to creditors and/or stockholders, if any, would not be determined until the confirmation of any plan of reorganization. No assurance can be given as to what values, if any, would be ascribed in any potential Chapter 11 filing to each of these constituencies or what types or amounts of distributions, if any, they would receive. If certain requirements of the Bankruptcy Code are met, a plan of reorganization can be confirmed notwithstanding its rejection by equity holders and notwithstanding the fact that equity holders do not receive or retain any property on account of their equity interests under the plan of reorganization. Unless there is significant improvement in market conditions or we are otherwise able to restructure our indebtedness without filing for Chapter 11 protection, we believe it is very unlikely that our common stockholders would receive any recovery in a Chapter 11 proceeding and it is also unlikely that the holders of our Convertible Preferred Stock would receive any meaningful recovery due in both cases to their relative positions with respect to our outstanding obligations which are senior to their respective equity interests.

Item 2 - Unregistered Sale of Equity Securities and Use of Proceeds

None

Item 3 - Defaults Upon Senior Securities

The Company’s Board of Directors did not declare a dividend on the Company’s 5.75% Series A cumulative convertible perpetual preferred stock (“Convertible Preferred Stock”) for the fourth quarter of 2008 or the first and second quarters of 2009, which dividends would have been paid on January 15, April 15, 2009 and July 15, 2009. Therefore, as of August 4, 2009, the Company has Convertible Preferred Stock dividends in arrears that total approximately $6.2 million.

Item 4 - Submission of Matters to a Vote of Security Holders	None
Item 5 - Other Information	None

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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 Appendix A to the Joint Proxy Statement/Prospectus contained in the Company’s Registration Statement on Form S-4/A filed on January 15, 1997 (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 by and among Contango STEP, L.P., Contango Oil & Gas Company, Edge Petroleum Exploration Company and Edge Petroleum Corporation, dated as of October 7, 2004 (Incorporated by reference from exhibit 2.1 to the Company’s Current Report on Form 8-K filed October 12, 2004).

2.4 —		Purchase and Sale Agreement, dated as of September 21, 2005 among Pearl Energy Partners, Ltd., and Cibola Exploration Partners, L.P., as Sellers; and Edge Petroleum Exploration Company as Buyer and Edge Petroleum Corporation as Guarantor (Incorporated by reference from exhibit 2.1 to the Company’s Current Report on Form 8-K filed October 19, 2005).

2.5 —		Stock Purchase Agreement by and among Jon L. Glass, Craig D. Pollard, Leigh T. Prieto, Yorktown Energy Partners V, L.P., Yorktown Energy Partners VI, L.P., Cinco Energy Corporation, and Edge Petroleum Exploration Company and Edge Petroleum Corporation, dated as of September 21, 2005 (Incorporated by reference from exhibit 2.5 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2005).

2.6 —		Letter Agreement dated November 18, 2005 by and among Edge Petroleum Exploration Company, Cinco Energy Corporation and Sellers (Incorporated by reference from exhibit 2.02 to the Company’s Current Report on Form 8-K filed December 6, 2005). Pursuant to Item 601(b)(2) of Regulation S-K, the Company had omitted certain Schedules to the Letter Agreement (all of which are listed therein) from this Exhibit 2.6. It hereby agrees to furnish a supplemental copy of any such omitted item to the SEC on its request.

2.7 —		Agreement and Plan of Merger, dated July 14, 2008, among Chaparral Energy, Inc., Chaparral Exploration, L.L.C. and Edge Petroleum Corporation (Incorporated by reference from exhibit 2.1 to the Company’s Current Report on Form 8-K filed July 15, 2008). Pursuant to Item 601(b)(2) of Regulation S-K, the Company had omitted the disclosure schedules to the Merger Agreement from this Exhibit 2.1. It hereby agrees to furnish a supplemental copy of any such omitted item to the SEC on its request.

3.1 —		Restated Certificate of Incorporation of the Company effective January 27, 1997 (Incorporated by reference from exhibit 3.1 to the Company’s Current Report on Form 8-K filed April 29, 2005).

3.2 —		Certificate of Amendment to the Restated Certificate of Incorporation of the Company effective January 31, 1997 (Incorporated by reference from exhibit 3.2 to the Company’s Current Report on Form 8-K filed April 29, 2005).

3.3 —		Certificate of Amendment to the Restated Certificate of Incorporation of the Company effective April 27, 2005 (Incorporated by reference from exhibit 3.3 to the Company’s Current Report on Form 8-K filed April 29, 2005).

3.4 —		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 (File No. 000-22149)).

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3.5 —	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 (File No. 000-22149)).

3.6 —	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).

3.7 —	Certificate of Designations establishing the 5.75% Series A cumulative convertible perpetual preferred stock, dated January 25, 2007 (Incorporated by reference to exhibit 3.1 to the Company’s Current Report on Form 8-K filed January 30, 2007).

3.8 —	Third Amendment to Bylaws of Edge Petroleum Corporation on October 21, 2008 (Incorporated by reference to exhibit 3.4 to the Company’s Current Report on Form 8-K filed October 23, 2008).

4.1 —	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)).

4.2 —	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)).

4.3 —	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)).

4.4 —	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)).

4.5 —	Fourth Amended and Restated Credit Agreement dated January 31, 2007 by and among Edge Petroleum Corporation, as borrower, and Union Bank of California, N.A., as Administrative Agent and Issuing Lender, and the other lenders party thereto (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed on February 5, 2007).

4.6 —	Amendments No. 1, 2 and 3 to the Fourth Amended and Restated Credit Agreement dated as of July 11, 2007, December 10, 2007 and May 8, 2008, respectively, by and among Edge Petroleum Corporation, as borrower, and Union Bank of California, N.A., as Administrative Agent and Issuing Lender, and the other lenders party thereto (Incorporated by reference from exhibit 4.9 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ending March 31, 2008 filed on May 12, 2008).

4.7 —	Consent, executed July 11, 2008, among Edge Petroleum Corporation, the Lenders party thereto and Union Bank of California, N.A., as administrative agent for such Lenders (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed July 15, 2008).

4.8 —	Letter Agreement dated November 5, 2008 by and among Edge Petroleum Corporation, Union Bank of California, N.A., as Administrative Agent and Issuing Lender, and the other lenders party thereto (Incorporated by reference from exhibit 4.11 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ending September 30, 2008 filed November 10, 2008).

4.9 —	Consent and Agreement, executed February 9, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such

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	lenders. (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed February 9, 2009).

4.10 —	Consent and Agreement, executed March 10, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders. (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed March 10, 2009).

4.11 —	Consent and Amendment No. 4 executed March 16, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders. (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed March 16, 2009).

4.12 —	Amendment No. 5, executed May 15, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders. (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed May 15, 2009).

4.13 —	Amendment No. 6, executed May 29, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders. (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed May 29, 2009).

4.14 —	Amendment No. 7, executed June 30, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders. (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed July 1, 2009).

4.15 —	Amendment No. 8, executed July 31, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank, N.A. (f/k/a Union Bank of California, N.A.), as administrative agent for such lenders. (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed August 3, 2009).

†10.1 —	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)).

†10.2 —	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)).

†10.3 —	Employment Agreement dated as of November 16, 1998, by and between the Company and John W. Elias (Incorporated by reference from exhibit 10.12 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 000-22149)).

†10.4 —	Amended and Restated Incentive Plan of Edge Petroleum Corporation as Amended and Restated Effective as of August 1, 2006 (Incorporated by reference from exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ending June 30, 2006).

†10.5 —	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 (File No. 000-22149)).

†10.6 —	Edge Petroleum Corporation Incentive Plan “Director Non-Qualified Stock Option Agreement” by and between Edge Petroleum Corporation and the Directors named therein (Incorporated by

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	reference from exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999 (File No. 000-22149)).

†10.7 —	Form of Director’s Restricted Stock Award Agreement under the Incentive Plan of Edge Petroleum Corporation (Incorporated by reference from exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004).

†10.8 —	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 (File No. 000-22149)).

†10.9 —	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)).

†10.10 —	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)).

†10.11 —	Summary of Compensation of Non-Employee Directors (Incorporated by reference from exhibit 10.11 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008).

†10.12 —	Salaries and Certain Other Compensation of Executive Officers (Incorporated by reference from exhibit 10.12 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008).

†10.13 —	Description of Annual Cash Bonus Program for Executive Officers (Incorporated by reference from exhibit 10.2 to the Company’s Current Report on Form 8-K filed March 12, 2007).

†10.14 —	New Base Salaries and Long-Term Incentive Awards for Certain Executive Officers (Incorporated by reference from exhibit 10.1 to the Company’s Current Report on Form 8-K filed August 29, 2006).

10.15 —	Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated November 16, 2006 (Incorporated by reference to exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 16, 2007).

10.16 —	Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated November 16, 2006 (Incorporated by reference to exhibit 10.2 to the Company’s Current Report on Form 8-K filed January 16, 2007).

10.17 —	First Amendment of Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated December 16, 2006 (Incorporated by reference to exhibit 10.3 to the Company’s Current Report on Form 8-K filed January 16, 2007).

10.18 —	Second Amendment of Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated January 15, 2007 (Incorporated by reference to exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 19, 2007).

10.19 —	First Amendment of Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated January 15, 2007 (Incorporated by reference to exhibit 10.2 to the Company’s Current Report on Form 8-K filed January 19, 2007).

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10.20 —	Third Amendment of Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated January 31, 2007 (Incorporated by reference to exhibit 10.6 to the Company’s Current Report on Form 8-K filed February 5, 2007).

†10.21 —	New Base Salaries of Executive Officers (Incorporated by reference from Exhibit 10.1 to the Company’s Current Report on Form 8-K filed March 12, 2007).

†10.22 —	Form of Amended and Restated Severance Agreement dated April 3, 2008, between the Company and Executive Officers of the Company Named Therein (Incorporated by reference from exhibit 10.1 to the Company’s Current Report on Form 8-K filed April 4, 2008).

†10.23 —	Amended and Restated Severance Agreement dated April 3, 2008, between the Company and John W. Elias (Incorporated by reference from exhibit 10.2 to the Company’s Current Report on Form 8-K filed April 4, 2008).

†10.24 —	Amended and Restated Employment Agreement dated April 3, 2008, between the Company and John W. Elias (Incorporated by reference from exhibit 10.3 to the Company’s Current Report on Form 8-K filed April 4, 2008).

†10.25 —	First Amendment to Amended and Restated Severance Agreement, dated July 14, 2008, between the Company and John W. Elias (Incorporated by reference from exhibit 10.1 to the Company’s Current Report on Form 8-K filed July 15, 2008).

†10.26 —	First Amendment to Second Amended and Restated Severance Agreement, dated July 14, 2008, between the Company and Executive Officers of the Company Named Therein (Incorporated by reference from exhibit 10.2 to the Company’s Current Report on Form 8-K filed July 15, 2008).

†10.27 —	Fourth Amended and Restated Severance Agreement among Edge Petroleum Corporation and Kirsten A. Hink (Incorporated by reference from exhibit 10.1 to the Company’s Current Report on Form 8-K filed April 6, 2009).

10.28 —	Merger Termination Agreement, dated December 16, 2008, among Chaparral Energy, Inc., Chaparral Exploration, L.L.C. and Edge Petroleum Corporation (Incorporated by reference to exhibit 10.1 to the Company’s Current Report on Form 8-K filed December 17, 2008).

10.29 —	Termination and Settlement Agreement, dated December 16, 2008, among Magnetar Financial LLC , Investment Partners II (B), LLC, QRA SR, LLC, Triangle Peak Partners Private Equity, LP, Post Oak Energy Capital, LP, Chaparral Energy, Inc., Chaparral Exploration, L.L.C. and Edge Petroleum Corporation (Incorporated by reference to exhibit 10.2 to the Company’s Current Report on Form 8-K filed December 17, 2008).

*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 Gary L. Pittman, 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 Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2 —	Certification by Gary L. Pittman, Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith.

† Denotes management or compensatory contract, arrangement or agreement.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		EDGE PETROLEUM CORPORATION,
		A DELAWARE CORPORATION
		(REGISTRANT)


Date	August 6, 2009	/s/ John W. Elias
		John W. Elias
		Chairman of the Board, President and
		Chief Executive Officer


Date	August 6, 2009	/s/ Gary L. Pittman
		Gary L. Pittman
		Executive Vice President and
		Chief Financial Officer


Date	August 6, 2009	/s/ Kirsten A. Hink
		Kirsten A. Hink
		Vice President and Controller

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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 Appendix A to the Joint Proxy Statement/Prospectus contained in the Company’s Registration Statement on Form S-4/A filed on January 15, 1997 (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 by and among Contango STEP, L.P., Contango Oil & Gas Company, Edge Petroleum Exploration Company and Edge Petroleum Corporation, dated as of October 7, 2004 (Incorporated by reference from exhibit 2.1 to the Company’s Current Report on Form 8-K filed October 12, 2004).

2.4 —		Purchase and Sale Agreement, dated as of September 21, 2005 among Pearl Energy Partners, Ltd., and Cibola Exploration Partners, L.P., as Sellers; and Edge Petroleum Exploration Company as Buyer and Edge Petroleum Corporation as Guarantor (Incorporated by reference from exhibit 2.1 to the Company’s Current Report on Form 8-K filed October 19, 2005).

2.5 —		Stock Purchase Agreement by and among Jon L. Glass, Craig D. Pollard, Leigh T. Prieto, Yorktown Energy Partners V, L.P., Yorktown Energy Partners VI, L.P., Cinco Energy Corporation, and Edge Petroleum Exploration Company and Edge Petroleum Corporation, dated as of September 21, 2005 (Incorporated by reference from exhibit 2.5 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2005).

2.6 —		Letter Agreement dated November 18, 2005 by and among Edge Petroleum Exploration Company, Cinco Energy Corporation and Sellers (Incorporated by reference from exhibit 2.02 to the Company’s Current Report on Form 8-K filed December 6, 2005). Pursuant to Item 601(b)(2) of Regulation S-K, the Company had omitted certain Schedules to the Letter Agreement (all of which are listed therein) from this Exhibit 2.6. It hereby agrees to furnish a supplemental copy of any such omitted item to the SEC on its request.

2.7 —		Agreement and Plan of Merger, dated July 14, 2008, among Chaparral Energy, Inc., Chaparral Exploration, L.L.C. and Edge Petroleum Corporation (Incorporated by reference from exhibit 2.1 to the Company’s Current Report on Form 8-K filed July 15, 2008). Pursuant to Item 601(b)(2) of Regulation S-K, the Company had omitted the disclosure schedules to the Merger Agreement from this Exhibit 2.1. It hereby agrees to furnish a supplemental copy of any such omitted item to the SEC on its request.

3.1 —		Restated Certificate of Incorporation of the Company effective January 27, 1997 (Incorporated by reference from exhibit 3.1 to the Company’s Current Report on Form 8-K filed April 29, 2005).

3.2 —		Certificate of Amendment to the Restated Certificate of Incorporation of the Company effective January 31, 1997 (Incorporated by reference from exhibit 3.2 to the Company’s Current Report on Form 8-K filed April 29, 2005).

3.3 —		Certificate of Amendment to the Restated Certificate of Incorporation of the Company effective April 27, 2005 (Incorporated by reference from exhibit 3.3 to the Company’s Current Report on Form 8-K filed April 29, 2005).

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3.4 —	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 (File No. 000-22149)).

3.5 —	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 (File No. 000-22149)).

3.6 —	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).

3.7 —	Certificate of Designations establishing the 5.75% Series A cumulative convertible perpetual preferred stock, dated January 25, 2007 (Incorporated by reference to exhibit 3.1 to the Company’s Current Report on Form 8-K filed January 30, 2007).

3.8 —	Third Amendment to Bylaws of Edge Petroleum Corporation on October 21, 2008 (Incorporated by reference to exhibit 3.4 to the Company’s Current Report on Form 8-K filed October 23, 2008).

4.1 —	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)).

4.2 —	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)).

4.3 —	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)).

4.4 —	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)).

4.5 —	Fourth Amended and Restated Credit Agreement dated January 31, 2007 by and among Edge Petroleum Corporation, as borrower, and Union Bank of California, N.A., as Administrative Agent and Issuing Lender, and the other lenders party thereto (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed on February 5, 2007).

4.6 —	Amendments No. 1, 2 and 3 to the Fourth Amended and Restated Credit Agreement dated as of July 11, 2007, December 10, 2007 and May 8, 2008, respectively, by and among Edge Petroleum Corporation, as borrower, and Union Bank of California, N.A., as Administrative Agent and Issuing Lender, and the other lenders party thereto (Incorporated by reference from exhibit 4.9 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ending March 31, 2008 filed on May 12, 2008).

4.7 —	Consent, executed July 11, 2008, among Edge Petroleum Corporation, the Lenders party thereto and Union Bank of California, N.A., as administrative agent for such Lenders (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed July 15, 2008).

4.8 —	Letter Agreement dated November 5, 2008 by and among Edge Petroleum Corporation, Union Bank of California, N.A., as Administrative Agent and Issuing Lender, and the other lenders party thereto (Incorporated by reference from exhibit 4.11 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ending September 30, 2008 filed November 10, 2008).

4.9 —	Consent and Agreement, executed February 9, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders.

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	(Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed February 9, 2009).

4.10 —	Consent and Agreement, executed March 10, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders. (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed March 10, 2009).

4.11 —	Consent and Amendment No. 4 executed March 16, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders. (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed March 16, 2009).

4.12 —	Amendment No. 5, executed May 15, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders. (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed May 15, 2009).

4.13 —	Amendment No. 6, executed May 29, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders. (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed May 29, 2009).

4.14 —	Amendment No. 7, executed June 30, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders. (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed July 1, 2009).

4.15 —	Amendment No. 8, executed July 31, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank, N.A. (f/k/a Union Bank of California, N.A.), as administrative agent for such lenders. (Incorporated by reference from exhibit 4.1 to the Company’s Current Report on Form 8-K filed August 3, 2009).

†10.1 —	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)).

†10.2 —	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)).

†10.3 —	Employment Agreement dated as of November 16, 1998, by and between the Company and John W. Elias (Incorporated by reference from exhibit 10.12 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 000-22149)).

†10.4 —	Amended and Restated Incentive Plan of Edge Petroleum Corporation as Amended and Restated Effective as of August 1, 2006 (Incorporated by reference from exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ending June 30, 2006).

†10.5 —	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 (File No. 000-22149)).

†10.6 —	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 (File No. 000-22149)).

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†10.7 —	Form of Director’s Restricted Stock Award Agreement under the Incentive Plan of Edge Petroleum Corporation (Incorporated by reference from exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004).

†10.8 —	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 (File No. 000-22149)).

†10.9 —	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)).

†10.10 —	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)).

†10.11 —	Summary of Compensation of Non-Employee Directors (Incorporated by reference from exhibit 10.11 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008).

†10.12 —	Salaries and Certain Other Compensation of Executive Officers (Incorporated by reference from exhibit 10.12 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008).

†10.13 —	Description of Annual Cash Bonus Program for Executive Officers (Incorporated by reference from exhibit 10.2 to the Company’s Current Report on Form 8-K filed March 12, 2007).

†10.14 —	New Base Salaries and Long-Term Incentive Awards for Certain Executive Officers (Incorporated by reference from exhibit 10.1 to the Company’s Current Report on Form 8-K filed August 29, 2006).

10.15 —	Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated November 16, 2006 (Incorporated by reference to exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 16, 2007).

10.16 —	Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated November 16, 2006 (Incorporated by reference to exhibit 10.2 to the Company’s Current Report on Form 8-K filed January 16, 2007).

10.17 —	First Amendment of Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated December 16, 2006 (Incorporated by reference to exhibit 10.3 to the Company’s Current Report on Form 8-K filed January 16, 2007).

10.18 —	Second Amendment of Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated January 15, 2007 (Incorporated by reference to exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 19, 2007).

10.19 —	First Amendment of Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated January 15, 2007 (Incorporated by reference to exhibit 10.2 to the Company’s Current Report on Form 8-K filed January 19, 2007).

10.20 —	Third Amendment of Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated January 31, 2007 (Incorporated by reference to exhibit 10.6 to the Company’s Current Report on Form 8-K filed February 5, 2007).

†10.21 —	New Base Salaries of Executive Officers (Incorporated by reference from Exhibit 10.1 to the Company’s Current Report on Form 8-K filed March 12, 2007).

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†10.22 —	Form of Amended and Restated Severance Agreement dated April 3, 2008, between the Company and Executive Officers of the Company Named Therein (Incorporated by reference from exhibit 10.1 to the Company’s Current Report on Form 8-K filed April 4, 2008).

†10.23 —	Amended and Restated Severance Agreement dated April 3, 2008, between the Company and John W. Elias (Incorporated by reference from exhibit 10.2 to the Company’s Current Report on Form 8-K filed April 4, 2008).

†10.24 —	Amended and Restated Employment Agreement dated April 3, 2008, between the Company and John W. Elias (Incorporated by reference from exhibit 10.3 to the Company’s Current Report on Form 8-K filed April 4, 2008).

†10.25 —	First Amendment to Amended and Restated Severance Agreement, dated July 14, 2008, between the Company and John W. Elias (Incorporated by reference from exhibit 10.1 to the Company’s Current Report on Form 8-K filed July 15, 2008).

†10.26 —	First Amendment to Second Amended and Restated Severance Agreement, dated July 14, 2008, between the Company and Executive Officers of the Company Named Therein (Incorporated by reference from exhibit 10.2 to the Company’s Current Report on Form 8-K filed July 15, 2008).

†10.27 -	Fourth Amended and Restated Severance Agreement among Edge Petroleum Corporation and Kirsten A. Hink (Incorporated by reference from exhibit 10.1 to the Company’s Current Report on Form 8-K filed April 6, 2009).

10.28 —	Merger Termination Agreement, dated December 16, 2008, among Chaparral Energy, Inc., Chaparral Exploration, L.L.C. and Edge Petroleum Corporation (Incorporated by reference to exhibit 10.1 to the Company’s Current Report on Form 8-K filed December 17, 2008).

10.29 —	Termination and Settlement Agreement, dated December 16, 2008, among Magnetar Financial LLC , Investment Partners II (B), LLC, QRA SR, LLC, Triangle Peak Partners Private Equity, LP, Post Oak Energy Capital, LP, Chaparral Energy, Inc., Chaparral Exploration, L.L.C. and Edge Petroleum Corporation (Incorporated by reference to exhibit 10.2 to the Company’s Current Report on Form 8-K filed December 17, 2008).

*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 Gary L. Pittman, 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 Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2 —	Certification by Gary L. Pittman, Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith.

† Denotes management or compensatory contract, arrangement or agreement.

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FORWARD LOOKING STATEMENTS

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INDEX TO EXHIBITS

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