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 September 30, 2009

	OR

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		(I.R.S. Employer
Incorporation or Organization)		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. xYes o 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). oYes o 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 o		Accelerated filer x

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). oYes 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 November 6, 2009
Common Stock		28,905,613

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EDGE PETROLEUM CORPORATION

Table of Contents

		Page No.
Part I. Financial Information
Item 1. Financial Statements (Unaudited):
Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008		3
Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2009 and 2008		4
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2008		5
Consolidated Statement of Stockholders’ Equity for the Nine Months Ended September 30, 2009		6
Notes to the Consolidated Financial Statements		7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		32
Item 3. Qualitative and Quantitative Disclosures About Market Risk		64
Item 4. Controls and Procedures		65
Part II. Other Information
Item 1. Legal Proceedings		66
Item 1A. Risk Factors		67
Item 2. Unregistered Sale of Equity Securities and Use of Proceeds		72
Item 3. Defaults Upon Senior Securities		72
Item 4. Submission of Matters to a Vote of Security Holders		73
Item 5. Other Information		73
Item 6. Exhibits		73
Signatures		79

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EDGE PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

	September 30,			December 31,
	2009			2008
	(Unaudited)
	(in thousands, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	13,449		$	8,475
Accounts receivable, trade, net of allowance	8,749			14,548
Accounts receivable, joint interest owners and other, net of allowance	850			5,689
Derivative financial instruments	5,651			15,407
Other current assets	2,790			4,591

Total current assets	31,489			48,710

PROPERTY AND EQUIPMENT, net – full cost method of accounting for oil and natural gas properties (including unevaluated costs of $24.4 million and $16.4 million at September 30, 2009 and December 31, 2008, respectively)	215,467			307,059

OTHER ASSETS	613			1,828

TOTAL ASSETS	$	247,569		$	357,597

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable, trade	$	387		$	3,086
Accrued liabilities	7,330			8,779
Current portion of delivery commitment	1,987			—
Accrued interest payable	1,100			579
Current portion of debt	226,500			239,000
Asset retirement obligation	558			547

Total current liabilities	237,862			251,991

ASSET RETIREMENT OBLIGATION – long-term	6,274			6,011

OTHER NON-CURRENT LIABILITIES	102			102

DELIVERY COMMITMENT	—			2,005

Total liabilities	244,238			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 September 30, 2009 and December 31, 2008	29			29
Common stock, $0.01 par value; 60,000,000 shares authorized; 28,905,613, and 28,833,546 shares issued and outstanding at September 30, 2009 and December 31, 2008, respectively	289			288
Additional paid-in capital	424,508			423,951
Retained deficit	(421,495		)	(326,780		)

Total stockholders’ equity	3,331			97,488

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	247,569		$	357,597

See accompanying notes to consolidated financial statements.

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EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in thousands, except per share amounts)
OIL AND NATURAL GAS REVENUE:
Oil and natural gas sales	$	10,125		$	43,136		$	34,797		$	139,212
Gain (loss) on derivatives	1,011			63,505			12,188			(22,452		)
Total revenue	11,136			106,641			46,985			116,760

OPERATING EXPENSES:
Oil and natural gas operating expenses	3,171			4,039			10,820			12,452
Severance and ad valorem taxes	324			2,654			2,672			8,136
Depletion, depreciation, amortization and accretion	6,720			21,874			24,348			70,767
Impairment of oil and natural gas properties	—			129,520			78,254			129,520
General and administrative expenses	5,152			6,380			14,666			15,592

Total operating expenses	15,367			164,467			130,760			236,467

OPERATING LOSS	(4,231		)	(57,826		)	(83,775		)	(119,707		)

OTHER INCOME AND EXPENSE:
Other income	5			156			17			257
Interest expense, net of amounts capitalized	(3,016		)	(2,815		)	(8,328		)	(9,323		)
Amortization of deferred loan costs	—			(239		)	(1,465		)	(717		)
Reorganization expenses	(1,122		)	—			(1,122		)	—

LOSS BEFORE INCOME TAXES	(8,364		)	(60,724		)	(94,673		)	(129,490		)

INCOME TAX BENEFIT (EXPENSE)	(42		)	20,714			(42		)	45,478

NET LOSS	(8,406		)	(40,010		)	(94,715		)	(84,012		)
Preferred Stock Dividends	—			(2,066		)	—			(6,199		)
NET LOSS TO COMMON STOCKHOLDERS	$	(8,406	)	$	(42,076	)	$	(94,715	)	$	(90,211	)

BASIC LOSS PER SHARE	$	(0.36	)	$	(1.47	)	$	(3.50	)	$	(3.15	)

DILUTED LOSS PER SHARE	$	(0.36	)	$	(1.47	)	$	(3.50	)	$	(3.15	)

BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING	28,873			28,690			28,860			28,636

DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING	28,873			28,690			28,860			28,636

See accompanying notes to consolidated financial statements.

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EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

	Nine Months Ended September 30,
	2009			2008
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(94,715	)	$	(84,012	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Unrealized (gain) loss on the fair value of derivatives	9,756			(8,402		)
Loss on property	—			34
Deferred income taxes	—			(45,491		)
Depletion, depreciation, amortization and accretion	24,348			70,767
Impairment of oil and natural gas properties	78,254			129,520
Gain on ARO settlement	—			(83		)
Amortization of deferred loan costs	1,465			717
Bad debt expense	263			90
Share based compensation costs	558			2,371
Changes in assets and liabilities:
Decrease in accounts receivable, trade	5,696			1,555
Decrease in accounts receivable, joint interest owners	4,679			6,432
Decrease in other assets	388			244
Increase (decrease) in accounts payable, trade	(2,699		)	1,173
Increase (decrease) in accrued liabilities	(2,121		)	2,647
Decrease in other liabilities	(18		)	—
Increase (decrease) in accrued interest payable	521			(355		)

Net cash provided by operating activities	26,375			77,207

CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property and equipment additions	(11,064		)	(50,515		)
Decrease in drilling advances	1,163			798
Proceeds from the sale of oil and natural gas properties	328			19,173
Overhedge derivative settlements	672			(10,905		)

Net cash used in investing activities	(8,901		)	(41,449		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of debt	(12,500		)	(21,000		)
Preferred stock dividends paid	—			(6,199		)

Net cash used in financing activities	(12,500		)	(27,199		)

NET INCREASE IN CASH AND CASH EQUIVALENTS	4,974			8,559

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

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	13,449		$	15,722

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	—	—		72	1		(1		)	—			—

Share-based compensation costs	—	—		—	—		558			—			558

Net loss	—	—		—	—		—			(94,715		)	(94,715		)
BALANCE, SEPTEMBER 30, 2009	2,875	$	29	28,905	$	289	$	424,508		$	(421,495	)	$	3,331

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 the Company believes 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.

Going Concern – In light of the deficiency in the Company’s Revolving Facility, debt covenant violations, stock price decline, negative working capital, continued net losses and the Chapter 11 Cases (defined below) filed subsequent to September 30, 2009, 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 ended December 31, 2008 that raises substantial doubt about the Company’s ability to continue as a going concern. The Company’s ability to continue as a going concern is dependent upon the outcome of the Chapter 11 Cases and the Company does not expect to continue as a going concern at the conclusion of the Chapter 11 Cases.

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.

Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852 Reorganizations, which is applicable to companies in reorganization proceedings under Chapter 11, generally does not change the manner in which financial statements are prepared. However, it does require that the financial statements for periods subsequent to the filing of the Chapter 11 petition distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, due to the Chapter 11 Cases (defined below) filed on October 1, 2009, revenues, expenses (including professional fees), realized gains and losses, and provisions for losses that can be directly associated with the reorganization and restructuring of the business must be reported separately as reorganization items in the consolidated statements of operations beginning in the quarter ending December 31, 2009. The consolidated balance sheet must distinguish pre-petition liabilities subject to compromise from both those pre-petition liabilities that are not subject to compromise and from post-petition liabilities. Liabilities that may be affected by the plan must be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts. In addition, cash provided by reorganization items must be disclosed separately in the consolidated statement of cash flows. The Company adopted ASC 852 effective on October 1, 2009 and will segregate those items as outlined above for all reporting periods subsequent to such date.

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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 continued undertaking the evaluation and assessment of various financial and strategic alternatives throughout 2009 in order to address its liquidity issues and the impending maturity of the Company’s Fourth Amended and Restated Credit Agreement, as amended (the “Revolving Facility”) (see Note 4). In connection with this process, the Company also retained a new investment banking firm early in 2009 to assist further in the evaluation of its financial and strategic alternatives. On August 31, 2009, and after a series of other amendments extending the maturity date, the Company entered into Amendment No. 9 (“Amendment No. 9”) to its Revolving Facility, which changed the maturity date of the Revolving Facility from August 31, 2009 to September 30, 2009.

On September 30, 2009, the Company and its subsidiaries, Edge Petroleum Exploration Company (“EPEX”), Miller Exploration Company (“Miller”), Edge Petroleum Operating Company, Inc. (“EPOC”), Edge Petroleum Production Company (“EPPC”) and Miller Oil Corporation (“Miller Oil” and, together with EPEX, Miller, EPOC and EPPC, the “Subsidiaries” and, together with the Company, the “Debtors”) entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with PGP Gas Supply Pool No. 3 LLC (the “Proposed Purchaser”) pursuant to which the Proposed Purchaser will acquire all of the equity interests of each of the reorganized Subsidiaries (together, the “Equity Interests”). The Purchase Agreement contained certain covenants by the Debtors, including, among others, the agreement by each Debtor to file the Chapter 11 Cases (defined below) within five (5) business days of the date of signing of the Purchase Agreement (such bankruptcy filing date, the “Filing Date”).

Pursuant to the Purchase Agreement, the effective date for the sale of the Equity Interests of the reorganized Subsidiaries is June 30, 2009. The Purchase Price for the Equity Interests to be conveyed pursuant to the Purchase Agreement is $191 million, subject to adjustment for, among other things, a downward adjustment related to certain changes in the NYMEX Strip Price over the five year period from January 1, 2010 through December 31, 2014 (the “Gas Pricing Downward Adjustment”). The Gas Pricing Downward Adjustment is capped at approximately $23.9 million. In addition to the Gas Pricing Downward Adjustment, the Purchase Price is subject to further adjustments, as provided in the Purchase Agreement, including, among others, adjustments relating to (i) costs and expenses incurred by the Debtors in connection with the maintenance of the Debtors’ properties before and after the effective date, (ii) changes in the value of certain of the Company’s hedging contracts in the event of their early termination prior to the closing, (iii) gas imbalance volumes, (iv) environmental conditions, if any, (v) title defects and benefits, if any, (vi) taxes, (vii) proceeds of production before and after the effective date, (viii) unsold inventory as of the effective date, and (ix) prepaid items. The proceeds from the sale of the Equity Interests will be used to substantially reduce the Company’s indebtedness under the Revolving Facility. The Company currently has approximately $226.5 million of outstanding principal under its Revolving Facility which is substantially in excess of the proceeds expected to be received pursuant to the Purchase Agreement.

The Purchase Agreement also provides for (i) a break-up fee (the “Break-Up Fee”) of $6 million together with an expense reimbursement (the “Expense Reimbursement”) of up to $500,000 to the Proposed Purchaser under certain circumstances if the transaction is not ultimately consummated with the Proposed Purchaser, (ii) a deposit by the Proposed Purchaser of $8 million and (iii) a liquidated damages provision which generally provides for a limitation on damages in the amount of $8 million that may be claimed by the Company in the event of a breach by the Proposed Purchaser of certain of the terms and conditions of the Purchase Agreement (including certain breaches by the Proposed Purchaser which may result in the transactions

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contemplated by the Purchase Agreement not being consummated). The Proposed Purchaser may terminate the Purchase Agreement under certain circumstances, including if (i) the Bankruptcy Court (defined below) has not confirmed the joint plan of reorganization (the “Plan”) by the Filing Date plus one hundred five (105) days, (ii) the Bankruptcy Court denies the motion for entry of the bidding procedures order, fails to approve the Break-Up Fee or the Expense Reimbursement, or fails to enter the bidding procedures order by the Filing Date plus thirty (30) days (which conditions were each satisfied on October 5, 2009), (iii) the Company has breached any representation, warranty or covenant in the Purchase Agreement in any material respect and such breach results in a material adverse effect and the Company has failed to cure such breach within a reasonable time period after receiving written notice from the Proposed Purchaser of such breach, (iv) the Chapter 11 Cases have been converted to cases under Chapter 7 of the Bankruptcy Code (defined below), (v) the Chapter 11 Cases have been dismissed, (vi) a trustee or examiner with managerial powers is appointed, other than at the request of the Proposed Purchaser, under Bankruptcy Code Section 1104 and such trustee or examiner takes any action to interfere with or impair the transactions contemplated by the Purchase Agreement, (vii) the Company enters into an alternative transaction to the Purchase Agreement, (viii) the Company takes affirmative steps to effect an alternative transaction (except as otherwise provided in the bidding procedures order), or (ix) any event, circumstance, condition, fact, effect or other matter has occurred or exists which would, or would be reasonably likely to, give rise to the failure of any of the conditions precedent to the obligations of the Proposed Purchaser and cannot be cured within five (5) business days prior to closing. Consummation of the transactions contemplated by the Purchase Agreement is subject to higher and better offers received in a Bankruptcy Court-supervised auction, approval of the Bankruptcy Court and other customary closing conditions. The Company can terminate the Purchase Agreement under certain circumstances, including if the Proposed Purchaser has breached any representation, warranty or covenant in any material respect and the Proposed Purchaser has failed to cure such breach within five (5) business days after receiving written notice from the Company of such breach. The Company and the Proposed Purchaser can each terminate the Purchase Agreement under certain circumstances if the closing has not occurred on or before the 11th day after entry of the confirmation order in the Chapter 11 Cases and also if certain of the purchase price adjustments relating generally to title defects, title benefits, environmental matters, retained properties and casualty losses exceed a downward adjustment of greater than twenty percent (20%) of the Purchase Price.

Chapter 11 Cases - On October 1, 2009, the Debtors filed voluntary petitions (the “Chapter 11 Cases”) for reorganization relief under Chapter 11 of Title 11 of the United States Code, 11 U.S.C. §§ 101 et. seq., as amended (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas, Corpus Christi Division (the “Bankruptcy Court”). The Chapter 11 Cases are being jointly administered under the caption “In re: Edge Petroleum Corporation, et al.,” Case No. 09-20644(RSS). The Debtors remain in possession of their assets, and will continue to manage and operate their businesses and properties as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with Bankruptcy Code Sections 1107 and 1108 and other applicable provisions of the Bankruptcy Code, which require, among other things, Bankruptcy Court approval of certain matters outside the ordinary course of business. During the bankruptcy process, the Company, with the consent of the Pre-petition Lender, has received Bankruptcy Court authority to use cash flow from operations to provide working capital and financial resources necessary to allow business operations to continue as normal, including meeting obligations to employees and certain vendors, customers and others.

While no trustee, examiner, or official committee has been appointed, there can be no assurance that the Debtors will remain in possession of their assets and control of their businesses as debtors-in-possession and that a trustee will not be appointed to operate the businesses of the Debtors. The Debtors’ current business relationships and arrangements, and the Debtors’ ability to negotiate future business arrangements may be adversely affected by the filing of the Chapter 11 Cases.

On the Filing Date, the Company filed motions for an order granting authority to sell the Equity Interests, establishing bidding and auction procedures pursuant to Bankruptcy Code Sections 105, 363, 365 and 1123(b), designating the Proposed Purchaser as the “stalking horse bidder”, approving the Break-Up Fee and the Expense Reimbursement and setting a hearing date to approve the sale of the Equity Interests. After entry of the bid procedures order approving the bidding and auction process for all of the Equity Interests, or substantially all of the Debtors’ assets, the Debtors intend to engage in an auction process with any and all

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interested parties. The Company intends to request the Bankruptcy Court to approve the sale to the highest and best bid at the auction.

The Company has filed the Plan, which is subject to confirmation by the Bankruptcy Court and the approval of at least one of the impaired classes. The Company expects the Bankruptcy Court to enter a ruling on the Plan in early December 2009. There can be no assurance that the Plan will be acceptable to the Company’s creditors or confirmed by the Bankruptcy Court, or that the Disclosure Statement (defined below) will be approved by the Bankruptcy Court. Accordingly, all information contained in the Plan and the Disclosure Statement is subject to change, whether as a result of amendments or supplements thereto, actions of third parties or otherwise.

Plan Support and Lock-Up Agreement - In order to expedite the restructuring and reorganization of the Debtors as contemplated in the Purchase Agreement, the Company and the lenders to the Company’s Revolving Facility (the “Supporting Lenders”) who hold at least two-thirds of the outstanding principal amount pursuant to the Revolving Facility and who constitute more than one-half of the number of lenders under the Revolving Facility entered into a Plan Support and Lock-Up Agreement (the “Plan Support Agreement”) dated as of September 30, 2009 which contains as exhibits a draft of the Plan and a draft of the disclosure statement (the “Disclosure Statement”). The Plan Support Agreement requires the Supporting Lenders to (i) vote in favor of and support the Plan, (ii) vote against and not support any restructuring or reorganization that is not consistent with the Plan, and (iii) not (a) seek, solicit, support or encourage any other restructuring plan, (b) object to the Disclosure Statement or the solicitation of votes for the Plan or support any objection by any third party, or (c) take any action that is inconsistent with, or that would materially delay or obstruct the proposed solicitation, confirmation or consummation of, the Plan.

Under the Plan Support Agreement, the Debtors agreed, among other things, to use reasonable commercial efforts to (i) file the Plan and Disclosure Statement no later than five (5) days after the Filing Date, (ii) obtain Bankruptcy Court approval of the Disclosure Statement no later than forty-five (45) days after the Filing Date, (iii) obtain confirmation of the Plan by the Bankruptcy Court within ninety (90) days of the Filing Date, and (iv) consummate the Purchase Agreement or another agreement entered into pursuant to the bidding procedures order within (11) days of confirmation of the Plan, and not take any action that is materially inconsistent with, or that would materially delay consummation of, either the restructuring of the Debtors or the effectiveness of the Plan.

The support of the Supporting Lenders under the Plan Support Agreement will terminate under certain circumstances, including among others, if (i) the sum of certain proposed adjustments to the Purchase Price with respect to title defects, environmental matters, retained properties and casualty losses exceeds $5 million, (ii) the sum of certain allowed administrative and priority claims exceeds the specified reserve for administrative and priority claims, (iii) the Debtors file a plan of reorganization that is different from the Plan or shall modify or amend the Plan in any material respect without the written consent of the Administrative Agent, (iv) the Bankruptcy Court enters a cash collateral order or budget without the written consent of the required lenders that is materially different from those agreed upon by the Supporting Lenders and the Debtors, (v) the Plan shall not have been confirmed by the Bankruptcy Court in accordance with its terms within one hundred and five (105) days of the Filing Date, (vi) the Company shall withdraw or revoke the Plan or shall publicly announce its intention not to pursue confirmation of the Plan, (vii) a trustee shall have been appointed in any of the Chapter 11 Cases, any of the Chapter 11 Cases shall have been converted to cases under Chapter 7 of the Bankruptcy Code or any of the Chapter 11 Cases shall have been dismissed by order of the Bankruptcy Court, or (viii) the Plan shall not have been substantially consummated in accordance with its terms within one hundred twenty (120) days of the Filing Date.

NASDAQ Actions - On September 16, 2009, the Company received notice (the “Common Notice”) from The Nasdaq Stock Market (the “NASDAQ”) that the minimum bid price of the Company’s common stock was below $1.00 per share for 30 consecutive business days and that the Company was therefore not in compliance with the minimum bid price rule for continued listing set forth in Nasdaq Marketplace Rule 5450(a)(1).

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On October 2, 2009, the Company received notice (the “Notice”) from the NASDAQ that the Company’s common stock and 5.75% series A cumulative convertible perpetual preferred stock (the “Convertible Preferred Stock”) would be suspended from trading on the NASDAQ at the opening of business on October 13, 2009 pursuant to the NASDAQ’s Listing Rules 5100, 5110(b) and IM-5100-1, and that a Form 25-NSE would be filed with the SEC, which would remove the Company’s securities from listing and registration on the NASDAQ. According to the Notice, the determination to delist the Company’s securities was based on (i) the announcement by the Company on October 2, 2009 that it and each of its subsidiaries have filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code and the associated public interest concerns raised by such bankruptcy petitions; (ii) concerns regarding the residual equity interest of the existing listed securities holders; and (iii) concerns about the Company’s ability to sustain compliance with all requirements for continued listing on the NASDAQ.

The Company decided not to appeal the NASDAQ’s determination to a Hearings Panel, pursuant to the procedures set forth in the NASDAQ’s Listing Rule 5800 Series and the Company did not take any further action to appeal the NASDAQ’s decision, and therefore the Company’s securities were suspended from trading on October 13, 2009 and are expected to be delisted in November 2009.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Codification - On June 3, 2009, the Financial Accounting Standards Board (“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 ASC105-10, Generally Accepted Accounting Principles. FASB ASC 105-10 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. The Codification supersedes all existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification become non-authoritative. Following FASB ASC 105-10, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Rather, the FASB will issue Accounting Standards Updates, which will serve only to: (a) update the Codification; (b) provide background information about such 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 as such FASB Accounting Standards Updates. The GAAP hierarchy will be modified to include only two levels of GAAP: authoritative and non-authoritative. FASB ASC 105-10 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 the Codification on July 1, 2009. Since the Codification did not alter existing GAAP, it did not have an impact on our Consolidated Financial Statements. All references to pre-codified GAAP have been removed from this Form 10-Q and replaced with the Codification references.

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 successful-efforts method and the full-cost method. There are several significant differences between these methods. Among these differences is that, under the successful-efforts method, costs such as geological and geophysical (“G&G”), exploratory dry holes and delay rentals are expensed as incurred whereas under the full-cost method these types of charges are capitalized to their respective full-cost pool. In 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 FASB ASC 932-360-35-8, Impairment, where the first measurement for

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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 FASB ASC 932-10-S99-1, Extractive Activities – Oil and Gas – SEC Materials, (also 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 quarter ended September 30, 2009. At September 30, 2008 the Company recorded a net non-cash ceiling test impairment of $129.5 million ($84.2 million, net of tax), which was the result of declines in commodity prices and negative revisions in our proved reserve quantities at year-end 2007 and during 2008.

In accordance with FASB ASC 932-10-S99-2, Extractive Activities – Oil and Gas – SEC Materials, 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 September 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 FASB ASC 932-10-S99-2, Extractive Activities – Oil and Gas – SEC Materials, 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 $24.4 million and $16.4 million at September 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 the provisions of FASB ASC 825-10-65, Financial Instruments – Transition and Open Effective Date Information, effective April 1, 2009. FASB ASC 825-10-65 requires disclosures about fair value of financial instruments for publicly traded companies for interim 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 September 30, 2009 the Company believes it is not practicable to estimate the fair value of its outstanding debt in light of the Chapter 11 Cases that the Company filed (see Note 4). As provided by Amendment No. 9, the maturity date of the outstanding debt under the Revolving Facility was September 30, 2009. The Company failed to make the payment due under the Revolving Facility on or before September 30, 2009 which has resulted in an event of default under the Revolving Facility. The filing of the Chapter 11 Cases also constitutes an event of default under the Revolving Facility. The ability of the secured creditors to seek remedies to enforce

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their rights under the Revolving Facility is automatically stayed as a result of the filing of the Chapter 11 Cases. The automatic stay invoked by the filing of the Chapter 11 Cases effectively precludes any actions by the Company’s secured creditors to collect, assert, or recover a claim against the Debtors, subject to the applicable provisions of the Bankruptcy Code and orders granted by the Bankruptcy Court. The carrying amount of the Company’s debt under the Revolving Facility (including principal, fees and interest) as of September 30, 2009 was $227.6 million and the interest rate applied at September 30, 2009 was 5.75%.

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 September 30, 2009 and December 31, 2008, respectively. Accounts Receivable, Trade included an allowance for doubtful accounts of approximately $167,500 and $64,500 at September 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 (“ARO”) – 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 FASB ASC 410-20, Asset Retirement Obligations. Under FASB ASC 410-20, 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 ARO for oil and natural gas properties and related equipment during the nine months ended September 30, 2009 and 2008 are as follows:

	Nine Months Ended September 30,
	2009			2008
	(in thousands)
ARO, Beginning of Period	$	6,558		$	6,634
Liabilities incurred in the current period	11			615
Liabilities settled/sold in the current period	(12		)	(1,349		)
Accretion expense	288			283
Revisions	(13		)	152
ARO, End of Period	$	6,832		$	6,335

Current Portion	$	558		$	491
Long-Term Portion	$	6,274		$	5,844

During the nine months ended September 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 September 30, 2009 and December 31, 2008, our gas production was materially in balance, i.e. our cumulative portion of gas production

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taken and sold from wells in which the Company has 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 FASB ASC 718, Compensation - Stock Compensation, which requires that the compensation cost relating to share-based payment transactions be recognized in financial statements. Share-based compensation for the nine months ended September 30, 2009 was approximately $0.6 million, of which approximately $0.3 million was included in general and administrative expenses (“G&A”) and approximately $0.3 million was capitalized to oil and natural gas properties. Share-based compensation for the nine months ended September 30, 2008 was approximately $1.9 million, of which $1.5 million was included in general and administrative expenses and $0.4 million was capitalized to oil and natural gas properties.

During the nine months ended September 30, 2009, no restricted stock units (“RSUs”) were granted. At September 30, 2009, there were 143,424 RSUs outstanding, all of which were classified as equity instruments. No options were granted during the nine months ended September 30, 2009, and at period end, there were 359,000 vested unexercised options outstanding.

Income Taxes - Effective January 1, 2007, the Company adopted certain provisions of FASB ASC 740-10-25, Income Taxes. These provisions 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. ASC 740-10-25 also provides guidance on de-recognitions, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company also adopted provisions that require a company’s tax position to 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).

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in thousands)
Net Loss	$	(8,406	)	$	(40,010	)	$	(94,715	)	$	(84,012	)
Preferred Dividends	—			(2,066		)	—			(6,199		)
Net Loss Available to Common Stockholders	(8,406		)	(42,076		)	(94,715		)	(90,211		)

Other Comprehensive Income (Loss), Net of Tax	—			—			—			—
Total Comprehensive Loss	$	(8,406	)	$	(42,076	)	$	(94,715	)	$	(90,211	)

Fair Value Measurements – Effective January 1, 2008, the Company partially adopted FASB ASC 820, Fair Value Measurements and Disclosure, 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 FASB ASC 820 for the non-financial assets and non-financial liabilities that were delayed in adoption by FASB ASC 820-10-15, Fair Value Measurements and Disclosure – Scope and Scope Exceptions. Accordingly, the Company has now applied the provisions of FASB ASC 820 to its AROs. The adoption of FASB ASC 820 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 FASB ASC 855-10-25, Subsequent Events, effective April 1, 2009. FASB ASC 855-10-25 does not change the Company’s accounting policy for subsequent events, but instead incorporates existing accounting and disclosure requirements related to subsequent events into

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GAAP. FASB ASC 855-10-25 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. FASB ASC 855-10-25 requires the Company to disclose the date through which subsequent events have been evaluated. The adoption of FASB ASC 855-10-25 had no impact on the financial statements of the Company. The Company has evaluated subsequent events through November 9, 2009, the filing date of this Quarterly Report on Form 10-Q and included disclosures regarding the Chapter 11 Cases and certain NASDAQ actions (see Note 12 for additional discussion).

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.

In September 2009, the FASB issued an exposure draft of proposed Accounting Standards Update (“ASU”) entitled Oil and Gas Reserve Estimation and Disclosures. This proposed ASU would amend the FASB accounting standards to align FASB ASC 932, Extractive Activities – Oil and Gas with all of the aforementioned new SEC requirements. This proposal is expected to become an issued accounting update within the last quarter of 2009 with an effective date for annual reports for fiscal years ending on or after December 15, 2009. The Company is currently assessing the impact of this new authoritative accounting guidance on the Company’s consolidated financial statements.

In June 2009, the FASB issued guidance which amends the consolidation guidance applicable to variable interest entities. This guidance is included in FASB ASC 810, Consolidation. The amendments significantly reduce the previously required quantitative consolidation analysis, and require ongoing reassessments of whether a company is the primary beneficiary of a variable interest entity. This new guidance 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 the new guidance in FASB ASC 810 to impact its consolidated financial statements.

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 had a letter of credit sub-limit of $20 million. The Revolving Facility’s original maturity was scheduled for January 31, 2011.

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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 (defined below).

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.

At September 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 September 30, 2009, $226.5 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 the Company’s 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 its 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 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.

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· 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 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.

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· On August 31, 2009, the Company entered into Amendment No. 9 which changed the maturity date of the Revolving Facility from August 31, 2009 to September 30, 2009.

On September 30, 2009 all obligations under the Revolving Facility became automatically and immediately due and payable. The Company failed to make the payment due under the Revolving Facility on or before September 30, 2009 which has resulted in an event of default under the Revolving Facility. As a result, the Company filed for bankruptcy protection on October 1, 2009. The filing of the Chapter 11 Cases constitutes an additional event of default under the Company’s Revolving Facility. The total amount of principal, fees and interest outstanding under the Revolving Facility was approximately $227.6 million as of the Filing Date. However, the ability of the secured creditors to seek remedies to enforce their rights under the Revolving Facility is automatically stayed as a result of the filing of the Chapter 11 Cases. The automatic stay invoked by the filing of the Chapter 11 Cases effectively precludes any actions by our secured creditors to collect, assert, or recover a claim against the Debtors, subject to the applicable provisions of the Bankruptcy Code and orders granted by the Bankruptcy Court.

In connection with the Plan and to expedite the restructuring and reorganization of the Debtors as contemplated in the Purchase Agreement, the Company and the lenders to the Company’s Revolving Facility (the “Supporting Lenders”) who hold at least two-thirds of the outstanding principal amount pursuant to the Revolving Facility and who constitute more than one-half of the number of lenders under the Revolving Facility entered into the Plan Support Agreement dated as of September 30, 2009 which contains as exhibits a draft of the Plan and a draft of the Disclosure Statement. The Plan Support Agreement requires the Supporting Lenders to (i) vote in favor of and support the Plan, (ii) vote against and not support any restructuring or reorganization that is not consistent with the Plan, and (iii) not (a) seek, solicit, support or encourage any other restructuring plan, (b) object to the Disclosure Statement or the solicitation of votes for the Plan or support any objection by any third party, or (c) take any action that is inconsistent with, or that would materially delay or obstruct the proposed solicitation, confirmation or consummation of, the Plan.

The proceeds from the sale of the Equity Interests will be used to substantially reduce the Company’s indebtedness under the Revolving Facility. The Company currently has approximately $226.5 million of outstanding principal under its Revolving Facility which is substantially in excess of the proceeds expected to be received pursuant to the Purchase Agreement.

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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. In light of the actions taken by the NASDAQ in October 2009 and the Company’s filing of the Chapter 11 Cases, the Company does not expect to utilize this registration statement.

6. PREFERRED STOCK

In January 2007, 2,875,000 shares of its 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 and the Chapter 11 Cases. Cumulative dividends in arrears at September 30, 2009 amounted to approximately $7.9 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 therefore 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

· 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

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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 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;

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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.

Chapter 11 Cases. The Company advises investors of its strong belief that it is likely that there will be no value for the holders of the Company’s Convertible Preferred Stock in the Chapter 11 Cases and that the Plan does not currently contemplate such holders’ receiving any recovery absent a substantially higher and better offer for the Equity Interests that is sufficient to pay the Company’s secured and unsecured creditors in full (and with respect to the common stock to pay the liquidation preference on the Convertible Preferred Stock). In this regard, stockholders of a company in Chapter 11 generally receive value only if all claims of the company’s secured and unsecured creditors are fully satisfied. In this case and based on the expected proceeds from the sale of the Equity Interests which is substantially less than the amount the Company’s secured and unsecured creditors are owed, the Company’s management strongly believes all such secured and unsecured claims will not be fully satisfied, leading to its belief that the holders of the Company’s Convertible Preferred Stock and common stock will receive no value for their interests.

7. EARNINGS (LOSS) PER SHARE

The Company accounts for earnings (loss) per share in accordance with FASB ASC 260, Earnings per Share, which establishes the requirements for presenting earnings per share (“EPS”). FASB ASC 260 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.

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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 2008, conversion of the 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 September 30, 2009							Three Months Ended September 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	$	(8,406	)					$	(40,010	)
Less: Preferred stock dividends paid	—							(2,066		)
Less: Preferred stock dividends in arrears	(2,066		)					—

Basic EPS
Net loss to common stockholders	(10,472		)	28,873	$	(0.36	)	(42,076		)	28,690	$	(1.47	)
Effect of dilutive securities:
Restricted stock units	—			—	—			—			—	—
Common stock options	—			—	—			—			—	—
Convertible Preferred Stock	—			—	—			—			—	—
Diluted EPS
Net loss to common stockholders	$	(10,472	)	28,873	$	(0.36	)	$	(42,076	)	28,690	$	(1.47	)

	Nine Months Ended September 30, 2009							Nine Months Ended September 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	$	(94,715	)					$	(84,012	)
Less: Preferred stock dividends paid	—							(6,199		)
Less: Preferred stock dividends in arrears	(6,199		)					—

Basic EPS
Net loss to common stockholders	(100,914		)	28,860	$	(3.50	)	(90,211		)	28,636	$	(3.15	)
Effect of dilutive securities:
Restricted stock units	—			—	—			—			—	—
Common stock options	—			—	—			—			—	—
Convertible Preferred Stock	—			—	—			—			—	—
Diluted EPS
Net loss to common stockholders	$	(100,914	)	28,860	$	(3.50	)	$	(90,211	)	28,636	$	(3.15	)

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(1) In the calculation of diluted EPS for the three and nine months ended September 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 nine months ended September 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 nine months ended September 30, 2008, 20,361 and 53,031, respectively, equivalent shares of the Company’s restricted stock units and common stock options were excluded because the conversion would also be anti-dilutive.

8. INCOME TAXES

The Company accounts for income taxes under the asset and liability approach. 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 Chapter 11 Cases (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 report a tax benefit for the three or nine months ended September 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 September 30, 2009, the Company had $0.1 million of unrecognized tax benefits related to FASB ASC 740-10-25. There were no significant changes to the calculation since December 31, 2008. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlements of audits and the expiration of statutes of limitations prior to September 30, 2010.

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)
Nine months ended September 30, 2009:
Shares issued to satisfy restricted stock grants	99	$	1,246
Nine months ended September 30, 2008:
Shares issued to satisfy restricted stock grants	86	$	1,639
Shares issued to fund the Company’s matching contribution under the Company’s 401(k) plan	90	$	462

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For the nine months ended September 30, 2009 and 2008, the non-cash portion of Asset Retirement Costs was approximately $14,400 and $0.6 million, respectively. Preferred stock dividends declared but not yet paid at September 30, 2008 were $2.1 million, of which $1.7 million was accrued at September 30, 2008. There were no dividends declared or accrued at September 30, 2009. A supplemental disclosure of cash flow information is presented below:

	For the Nine Months Ended September 30,
	2009		2008
	(in thousands)
Cash paid during the period for:
Interest, net of amounts capitalized	$	7,826	$	9,678
Current state income tax	—		7
Federal alternative minimum tax payments	42		220

10. 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. 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 and Chapter 11 Cases, 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 FASB ASC 815-10, Derivatives and Hedging. 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

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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 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 FASB ASC 815-10 reflected on the balance sheet was as follows:

Price

Fair Value of Outstanding
Derivative Contracts as of

Transaction

Per

Volumes

Balance Sheet

September 30,

December 31,

Date

Type (1)

Beginning

Ending

Unit

Per Day

Location

2009

2008

(in thousands)

Natural Gas (2):

04/07

Collar

1/1/2009

12/31/2009

$7.75-$10.00

10,000 MMBtu

Derivative Financial Instruments - Current Assets

2,778

6,688

10/07

Collar

1/1/2009

12/31/2009

$7.75-$10.08

10,000 MMBtu

Derivative Financial Instruments - Current Assets

2,779

6,702

Crude Oil (3):

10/07

Collar

1/1/2009

12/31/2009

$70.00-$93.55

300 Bbl

Derivative Financial Instruments - Current Assets

2,017

Total derivatives not designated as hedging instruments under FASB ASC 815-10

5,651

15,407

(1) In October 2009, the caps on all of the Company’s derivative collars for the remaining term of the fourth quarter of 2009 were repurchased such that only the floors remain in place. The cost of this transaction was reimbursed by the Company’s proposed purchaser.

(2) 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.

(3) 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		Amount of Gain or (Loss) Recognized in Income on Derivative
Designated as Hedging Instruments under	Location of Gain or (Loss) Recognized in	Three Months Ended September 30,						Nine Months Ended September 30,
FASB ASC 815-10	Income on Derivative	2009			2008			2009			2008
		(in thousands)

Natural gas derivative realized settlements	Gain (loss) on derivatives – Total revenue	$	8,011		$	(5,011	)	$	20,880		$	(11,381	)
Crude oil derivative realized settlements	Gain (loss) on derivatives – Total revenue	57			(7,195		)	1,064			(19,473		)
Natural gas derivative unrealized change in fair value	Gain (loss) on derivatives – Total revenue	(6,937		)	56,417			(7,833		)	(61		)
Crude oil derivative unrealized change in fair value	Gain (loss) on derivatives – Total revenue	(120		)	19,294			(1,923		)	8,463
Gain (loss) on derivatives		$	1,011		$	63,505		$	12,188		$	(22,452	)

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11. FAIR VALUE MEASUREMENTS

As defined in FASB ASC 820, 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 FASB ASC 820, 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 FASB ASC 820 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

FASB ASC 820 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 FASB ASC 820 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.

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· 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.

· 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 September 30, 2009. As required by FASB ASC 820, 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

5,651

—

5,651

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 September 30, 2009					Nine Months Ended September 30, 2009
	Assets			Liabilities		Assets			Liabilities
	(in thousands)
Balance as of beginning of period	$	12,709		$	—	$	15,407		$	—
Realized and unrealized losses included in earnings	(15,126		)	—		(31,700		)	—
Realized and unrealized gains included in other comprehensive income	—			—		—			—
Settlements	8,068			—		21,944			—
Transfers in and/or out of Level 3	—			—		—			—
Balance as of September 30, 2009	$	5,651		$	—	$	5,651		$	—

Change in unrealized gains (losses) relating to instruments still held as of September 30, 2009	$	80		$	—	$	2,586		$	—

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.

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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.

Fair Value on a Nonrecurring Basis

On January 1, 2009, the Company adopted the provisions of FASB ASC 820 for non-financial assets and liabilities, which were delayed by FASB ASC 820-10-15. Therefore, the Company adopted the provisions of FASB ASC 820 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 FASB ASC 410-20. New assets and liabilities measured at fair value during the nine months ended September 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

Chapter 11 Cases - On October 1, 2009, the Debtors filed the Chapter 11 Cases for reorganization relief under Chapter 11 of Title 11 of the Bankruptcy Code. The Chapter 11 Cases are being jointly administered under the caption “In re: Edge Petroleum Corporation, et al.,” Case No. 09-20644(RSS).

The Debtors remain in possession of their assets, and will continue to manage and operate their businesses and properties as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with Bankruptcy Code Sections 1107 and 1108 and other applicable provisions of the Bankruptcy Code, which require, among other things, Bankruptcy Court approval of certain matters outside the ordinary course of business. During the bankruptcy process, with the consent of the Pre-petition Lenders and the approval of the Bankruptcy Court, the Company intends to use cash flow from operations to provide working capital and financial resources necessary to allow business operations to continue at a minimal level, including meeting obligations to employees and certain vendors, customers and others.

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The Company has filed the Plan, which is subject to confirmation by the Bankruptcy Court and the approval of at least one of the impaired classes. The Company expects the Bankruptcy Court to enter a ruling on the Plan in December 2009. There can be no assurance that the Plan will be acceptable to the Company’s creditors or confirmed by the Bankruptcy Court, or that the Disclosure Statement will be approved by the Bankruptcy Court. Accordingly, all information contained in the Plan and the Disclosure Statement is subject to change, whether as a result of amendments or supplements thereto, actions of third parties or otherwise.

NASDAQ Actions — On October 2, 2009, the Company received the Notice from the NASDAQ that the Company’s common stock and Convertible Preferred Stock would be delisted from the NASDAQ at the opening of business on October 13, 2009 pursuant to the NASDAQ’s Listing Rules 5100, 5110(b) and IM-5100-1, and that a Form 25-NSE would be filed with the SEC, which would remove the Company’s securities from listing and registration on the NASDAQ. According to the Notice, the determination to delist the Company’s securities was based on (i) the announcement by the Company on October 2, 2009 that it and each of its subsidiaries have filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code and the associated public interest concerns raised by such bankruptcy petitions; (ii) concerns regarding the residual equity interest of the existing listed securities holders; and (iii) concerns about the Company’s ability to sustain compliance with all requirements for continued listing on the NASDAQ.

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 $75,500 of this commitment through September 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. This liability was reclassified to current during the third quarter of 2009 as a result of the maturity date being less than 12 months away. 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. The Company expects that the Chapter 11 Cases may have a significant impact on this agreement.

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During 2008, the Company executed an 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 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 amount due Integrys related to this agreement is $550,000 plus 8% interest per annum, for a total liability of approximately $0.6 million. The Company has delivered approximately $231,100 of this amount through September 30, 2009. The Company expects that the Chapter 11 Cases may have a significant impact on this agreement. This agreement was terminated by Integrys on October 31, 2009.

This contract is not considered a derivative, but has been designated as an annual sales contract under FASB ASC 815-10-15.

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 and will be impacted by the Company’s Chapter 11 Cases, 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 the Company 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 has 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, 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 believe it has meritorious defenses and counterclaims. In October 2009, the Company filed a suggestion of bankruptcy in this case.

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

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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 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. In October 2009, the Company filed with the court a notice of stay due to bankruptcy.

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, along with the Plaintiffs, settled the dispute in June 2009 by agreement pursuant to which the Plaintiffs received $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 filed an answer and intends to vigorously defend itself. In October 2009, the Company filed a suggestion of bankruptcy in this case.

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 us and filed an answer on our behalf. No trial date has been set. The Company believes it has meritorious defenses to this litigation and intends to vigorously defend itself. In October 2009, the Company filed a suggestion of bankruptcy in this case.

In re: Edge Petroleum Corporation, et al. - On October 1, 2009, the Company and its subsidiaries, Edge Petroleum Exploration Company, Miller Exploration Company, Edge Petroleum Operating Company, Inc., Edge Petroleum Production Company and Miller Oil Corporation, filed voluntary petitions (the “Bankruptcy Cases”) for reorganization relief under Chapter 11 of Title 11 of the United States Code, 11 U.S.C. §§ 101 et. seq., as amended (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas, Corpus Christi Division (the “Bankruptcy Court”). The Bankruptcy Cases are being jointly administered under the caption “In re: Edge Petroleum Corporation, et al.,” Case No. 09-20644(RSS). The Company intends to continue to operate its business as a debtor-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The Bankruptcy Cases are discussed in greater detail in Note 12.

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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 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 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”).

On June 3, 2009, the Financial Accounting Standards Board (“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 Accounting Standards Codification (“ASC”) 105-10, Generally Accepted Accounting Principles. FASB ASC 105-10 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 Securities and Exchange Commission (“SEC”) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The Codification supersedes all existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification become non-authoritative. Following FASB ASC 105-10, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Rather, the FASB will issue Accounting Standards Updates, which will serve only to: (a) update the Codification; (b) provide background information about such 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 as such FASB Accounting Standards Updates. The GAAP hierarchy was modified to include only two levels of GAAP: authoritative and non-authoritative. FASB ASC 105-10 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 the Codification on July 1, 2009. Since the Codification did not alter existing GAAP, it did not have an impact on our Consolidated Financial Statements. All references to pre-codified GAAP have been removed from this Form 10-Q and replaced with the Codification references.

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 all of our Quarterly Reports on Form 10-Q for 2009.

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

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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 primary focus in 2009 has been on capital preservation and resolving the uncertainty and liquidity challenges we faced, but continued depressed economic conditions and the deteriorating commodity prices of late 2008 and 2009 have made this difficult. Additionally these conditions were factors in our January 2009 borrowing base redetermination (see “Revolving Facility” below) and the change in the maturity date of our entire outstanding debt due under our Revolving Facility. Faced with these constraints, on October 1, 2009 we filed voluntary petitions (the “Chapter 11 Cases”) for reorganization relief under Chapter 11 of Title 11 of the United States Code, 11 U.S.C. §§ 101 et. seq., as amended (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas, Corpus Christi Division (the “Bankruptcy Court”). We are now committed to consummating the Plan of Reorganization that we filed in connection with our Chapter 11 Cases.

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 have been operating under a severely reduced capital spending program in 2009 as we sought to resolve our liquidity challenges. We intend to operate our business as debtor-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court and consummate the Plan of Reorganization that we filed in connection with our Chapter 11 Cases.

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

· Recent Developments and Outlook — additional discussion relating to management’s outlook to the future of our business and our Chapter 11 Cases.

· 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 FASB ASC 820, Fair Value Measurements and Disclosure.

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

· Tax Matters — supplementary discussion of income tax matters.

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

Recent Developments and Outlook

Financial and Strategic Alternatives Process - In late 2007, we announced the hiring of a financial advisor to assist our 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, 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. We continued undertaking the evaluation and assessment of various financial and strategic alternatives throughout 2009 in order to address our liquidity issues and the impending maturity of our Fourth Amended and Restated Credit Agreement, as amended (the “Revolving Facility”) (see Liquidity and Capital Resources — Revolving Facility). In connection with this process, we also retained a new investment banking firm early in 2009 to assist further in the evaluation of our financial and strategic alternatives. On August 31, 2009, and after a series of other amendments extending the maturity date, we entered into Amendment No. 9 (“Amendment No. 9”) to our Revolving Facility, which changed the maturity date of the Revolving Facility from August 31, 2009 to September 30, 2009.

On September 30, 2009, we, along with our subsidiaries, Edge Petroleum Exploration Company (“EPEX”), Miller Exploration Company (“Miller”), Edge Petroleum Operating Company, Inc. (“EPOC”), Edge Petroleum Production Company (“EPPC”) and Miller Oil Corporation (“Miller Oil” and, together with EPEX, Miller, EPOC and EPPC, the “Subsidiaries” and, together with Edge, the “Debtors”) entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with PGP Gas Supply Pool No. 3 LLC (the “Proposed Purchaser”) pursuant to which the Proposed Purchaser will acquire all of the equity interests of each of the reorganized Subsidiaries (together, the “Equity Interests”). The Purchase Agreement contained certain covenants by the Debtors, including, among others, the agreement by each Debtor to file the Chapter 11 Cases within five (5) business days of the date of signing of the Purchase Agreement (such bankruptcy filing date, the “Filing Date”).

Pursuant to the Purchase Agreement, the effective date for the sale of the Equity Interests of the reorganized Subsidiaries is June 30, 2009. The consideration for the Equity Interests to be conveyed pursuant to the Purchase Agreement is $191 million, subject to adjustment for, among other things, a downward adjustment related to certain changes in the NYMEX Strip Price over the five year period from January 1, 2010 through December 31, 2014 (the “Gas Pricing Downward Adjustment”). The Gas Pricing Downward Adjustment is capped at approximately $23.9 million. In addition to the Gas Pricing Downward Adjustment, the Purchase Price is subject to further adjustments, as provided in the Purchase Agreement, including, among others, adjustments relating to (i) costs and expenses incurred by the Debtors in connection with the maintenance of the Debtors’ properties before and after the effective date, (ii) changes in the value of certain of the Company’s hedging contracts in the event of their early termination prior to the closing, (iii) gas imbalance volumes, (iv) environmental conditions, if any, (v) title defects and benefits, if any, (vi) taxes, (vii) proceeds of production before and after the effective date, (viii) unsold inventory as of the effective date, and (ix) prepaid items. The proceeds from the sale of the Equity Interests will be used to substantially reduce our indebtedness under the Revolving Facility. We currently have approximately $226.5 million of outstanding principal under our Revolving Facility which is substantially in excess of the proceeds expected to be received pursuant to the Purchase Agreement.

The Purchase Agreement also (i) provides for a break-up fee (the “Break-Up Fee”) of $6 million together with an expense reimbursement (the “Expense Reimbursement”) of up to $500,000 to the Proposed Purchaser under certain circumstances if the transaction is not ultimately consummated with the Proposed Purchaser, (ii) a deposit by the Proposed Purchaser of $8 million and (iii) a liquidated damages provision which generally

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provides for a limitation on damages in the amount of $8 million that may be claimed by us in the event of a breach by the Proposed Purchaser of certain of the terms and conditions of the Purchase Agreement (including certain breaches by the Proposed Purchaser which may result in the transactions contemplated by the Purchase Agreement not being consummated). The Proposed Purchaser may terminate the Purchase Agreement under certain circumstances, including if (i) the Bankruptcy Court has not confirmed the joint plan of reorganization (the “Plan”) by the Filing Date plus one hundred five (105) days, (ii) the Bankruptcy Court denies the motion for entry of the bidding procedures order, fails to approve the Break-Up Fee or the Expense Reimbursement, or fails to enter the bidding procedures order by the Filing Date plus thirty (30) days (which conditions were each satisfied on October 5, 2009), (iii) the Company has breached any representation, warranty or covenant in the Purchase Agreement in any material respect and such breach results in a material adverse effect and we have failed to cure such breach within a reasonable time period after receiving written notice from the Proposed Purchaser of such breach, (iv) the Chapter 11 Cases have been converted to cases under Chapter 7 of the Bankruptcy Code, (v) the Chapter 11 Cases have been dismissed, (vi) a trustee or examiner with managerial powers is appointed, other than at the request of the Proposed Purchaser, under Bankruptcy Code Section 1104 and such trustee or examiner takes any action to interfere with or impair the transactions contemplated by the Purchase Agreement, (vii) we enter into an alternative transaction to the Purchase Agreement, (viii) we take affirmative steps to effect an alternative transaction (except as otherwise provided in the bidding procedures order), or (ix) any event, circumstance, condition, fact, effect or other matter has occurred or exists which would, or would be reasonably likely to, give rise to the failure of any of the conditions precedent to the obligations of the Proposed Purchaser and cannot be cured within five (5) business days prior to closing. Consummation of the transactions contemplated by the Purchase Agreement is subject to higher and better offers received in a Bankruptcy Court-supervised auction, approval of the Bankruptcy Court and other customary closing conditions. We can terminate the Purchase Agreement under certain circumstances, including if the Proposed Purchaser has breached any representation, warranty or covenant in any material respect and the Proposed Purchaser has failed to cure such breach within five (5) business days after receiving written notice from us of such breach. We and the Proposed Purchaser can each terminate the Purchase Agreement under certain circumstances if the closing has not occurred on or before the 11th day after entry of the confirmation order in the Chapter 11 Cases and also if certain of the purchase price adjustments relating generally to title defects, title benefits, environmental matters, retained properties and casualty losses exceed a downward adjustment of greater than twenty percent (20%) of the Purchase Price.

Chapter 11 Cases - On October 1, 2009, we filed the Chapter 11 Cases, which are being jointly administered under the caption “In re: Edge Petroleum Corporation, et al.,” Case No. 09-20644(RSS). We will remain in possession of our assets, and will continue to manage and operate our businesses and properties as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with Bankruptcy Code Sections 1107 and 1108 and other applicable provisions of the Bankruptcy Code, which require, among other things, Bankruptcy Court approval of certain matters outside the ordinary course of business. During the bankruptcy process, we intend to use cash flow from operations to provide working capital and financial resources necessary to allow business operations to continue as normal, including meeting obligations to employees and certain vendors, customers and others.

While no trustee, examiner, or official committee has been appointed, there can be no assurance that we will remain in possession of our assets and control of our businesses as debtors-in-possession and that a trustee will not be appointed to operate our businesses. Our current business relationships and arrangements, and our ability to negotiate future business arrangements may be adversely affected by the filing of the Chapter 11 Cases.

On the Filing Date, we filed motions for an order granting authority to sell the Equity Interests, establishing bidding and auction procedures pursuant to Bankruptcy Code Sections 105, 363, 365 and 1123(b), designating the Proposed Purchaser as the “stalking horse bidder”, approving the Break-Up Fee and the Expense Reimbursement and setting a hearing date to approve the sale of the Equity Interests. After entry of the bid procedures order approving the bidding and auction process for all of the Equity Interests, or substantially all of our assets, we intend to engage in an auction process with any and all interested parties. We intend to request the Bankruptcy Court to approve the sale to the highest and best bid at the auction.

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We have filed the Plan, which is subject to confirmation by the Bankruptcy Court and the approval of at least one of the impaired classes. We expect the Bankruptcy Court to enter a ruling on the Plan in early December 2009. There can be no assurance that the Plan will be acceptable to our creditors or confirmed by the Bankruptcy Court, or that the Disclosure Statement (defined below) will be approved by the Bankruptcy Court. Accordingly, all information contained in the Plan and the Disclosure Statement is subject to change, whether as a result of amendments or supplements thereto, actions of third parties or otherwise.

Plan Support and Lock-Up Agreement - In order to expedite the restructuring and reorganization of the Debtors as contemplated in the Purchase Agreement, we and the lenders to our Revolving Facility (the “Supporting Lenders”) who hold at least two-thirds of the outstanding principal amount pursuant to the Revolving Facility and who constitute more than one-half of the number of lenders under the Revolving Facility entered into a Plan Support and Lock-Up Agreement (the “Plan Support Agreement”) dated as of September 30, 2009 which contains as exhibits a draft of the Plan and a draft of the disclosure statement (the “Disclosure Statement”). The Plan Support Agreement requires the Supporting Lenders to (i) vote in favor of and support the Plan, (ii) vote against and not support any restructuring or reorganization that is not consistent with the Plan, and (iii) not (a) seek, solicit, support or encourage any other restructuring plan, (b) object to the Disclosure Statement or the solicitation of votes for the Plan or support any objection by any third party, or (c) take any action that is inconsistent with, or that would materially delay or obstruct the proposed solicitation, confirmation or consummation of, the Plan.

Under the Plan Support Agreement, we agreed, among other things, to use reasonable commercial efforts to (i) file the Plan and Disclosure Statement no later than five (5) days after the Filing Date, (ii) obtain Bankruptcy Court approval of the Disclosure Statement no later than forty-five (45) days after the Filing Date, (iii) obtain confirmation of the Plan by the Bankruptcy Court within ninety (90) days of the Filing Date, and (iv) consummate the Purchase Agreement or another agreement entered into pursuant to the bidding procedures order within (11) days of confirmation of the Plan, and not take any action that is materially inconsistent with, or that would materially delay consummation of, either our restructuring or the effectiveness of the Plan.

The support of the Supporting Lenders under the Plan Support Agreement will terminate under certain circumstances, including among others, if (i) the sum of certain proposed adjustments to the Purchase Price with respect to title defects, environmental matters, retained properties and casualty losses exceeds $5 million, (ii) the sum of certain allowed administrative and priority claims exceeds the specified reserve for administrative and priority claims, (iii) we file a plan of reorganization that is different from the Plan or shall modify or amend the Plan in any material respect without the written consent of the Administrative Agent, (iv) the Bankruptcy Court enters a cash collateral order or budget without the written consent of the required lenders that is materially different from those agreed upon by the Supporting Lenders and the Debtors, (v) the Plan shall not have been confirmed by the Bankruptcy Court in accordance with its terms within one hundred and five (105) days of the Filing Date, (vi) we shall withdraw or revoke the Plan or shall publicly announce its intention not to pursue confirmation of the Plan, (vii) a trustee shall have been appointed in any of the Chapter 11 Cases, any of the Chapter 11 Cases shall have been converted to cases under Chapter 7 of the Bankruptcy Code or any of the Chapter 11 Cases shall have been dismissed by order of the Bankruptcy Court, or (viii) the Plan shall not have been substantially consummated in accordance with its terms within one hundred twenty (120) days of the Filing Date.

NASDAQ Actions - On September 16, 2009, we received notice from The Nasdaq Stock Market (the “NASDAQ”) that the minimum bid price of our common stock was below $1.00 per share for 30 consecutive business days and that we were therefore not in compliance with the minimum bid price rule for continued listing set forth in Nasdaq Marketplace Rule 5450(a)(1).

On October 2, 2009, we received notice (the “Notice”) from the NASDAQ that our common stock and 5.75% series A cumulative convertible perpetual preferred stock (the “Convertible Preferred Stock”) would be delisted from the NASDAQ at the opening of business on October 13, 2009 pursuant to the NASDAQ’s Listing Rules 5100, 5110(b) and IM-5100-1, and that a Form 25-NSE would be filed with the SEC, which would remove our securities from listing and registration on the NASDAQ. According to the Notice, the determination to delist our securities was based on (i) the announcement by us on October 2, 2009 that we and each of our subsidiaries have filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code and

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the associated public interest concerns raised by such bankruptcy petitions; (ii) concerns regarding the residual equity interest of the existing listed securities holders; and (iii) concerns about our ability to sustain compliance with all requirements for continued listing on the NASDAQ.

We decided not to appeal the NASDAQ’s determination to a Hearings Panel, pursuant to the procedures set forth in the NASDAQ’s Listing Rule 5800 Series and we did not take any further action to appeal the NASDAQ’s decision, and therefore our securities were suspended from trading on the NASDAQ on October 13, 2009 and are expected to be delisted in November 2009.

Going Concern – In light of the deficiency in the Company’s Revolving Facility, debt covenant violations, stock price decline, negative working capital, continued net losses and the Chapter 11 Cases filed subsequent to September 30, 2009, 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 outcome of the Chapter 11 Cases and we do not expect to continue as a going concern at the conclusion of our Chapter 11 Cases.

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.

FASB ASC 852 Reorganizations, which is applicable to companies in reorganization proceedings under Chapter 11, generally does not change the manner in which financial statements are prepared. However, it does require that the financial statements for periods subsequent to the filing of the Chapter 11 petition distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Revenues, expenses (including professional fees), realized gains and losses, and provisions for losses that can be directly associated with the reorganization and restructuring of the business must be reported separately as reorganization items in the consolidated statements of operations beginning in the quarter ending December 31, 2009. The consolidated balance sheet must distinguish pre-petition liabilities subject to compromise from both those pre-petition liabilities that are not subject to compromise and from post-petition liabilities. Liabilities that may be affected by the plan must be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts. In addition, cash provided by reorganization items must be disclosed separately in the consolidated statement of cash flows. We adopted ASC 852 effective on October 1, 2009 and will segregate those items as outlined above for all reporting periods subsequent to such date.

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 outcome of the Chapter 11 Cases 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 collapse 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

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peaks in July 2008. Although crude oil prices have shown some recovery in 2009 rising to approximately $80.00 per barrel, natural gas prices have remained weak around $3.00 to $5.00 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 nine months 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 in connection with our Chapter 11 Cases.

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 the global economy, but the current conditions have made it difficult at times for us as we continued our 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. 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 September 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.

In 2009 we have operated under a severely limited capital spending program as we continued our review of financial and strategic alternatives. Our strategy has been to preserve liquidity and resolve the uncertainty and challenges we faced. We now intend to use cash flow from operations to provide working capital and financial resources necessary to allow business operations to continue at a minimal level, including meeting obligations

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to employees and certain vendors, customers and others as we proceed through consummation of our Plan of Reorganization that we filed in connection with our Chapter 11 Cases.

Divestitures

In the past, we have regularly reviewed 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 nine months of 2009, we completed the sale of various non-core properties in Texas for proceeds of $0.3 million and during the first nine months of 2008, we completed sales of a pipeline and certain working interests in approximately 120 properties located in Texas to various buyers for aggregate proceeds of approximately $19.2 million.

As discussed above, on September 30, 2009, the Debtors entered into the Purchase Agreement with the Proposed Purchaser pursuant to which the Proposed Purchaser will acquire the Equity Interests. Pursuant to the Purchase Agreement, the effective date for the sale of the Equity Interests of the reorganized Subsidiaries is June 30, 2009. The consideration for the Equity Interests to be conveyed pursuant to the Purchase Agreement is $191 million, subject to adjustment for, among other things, the Gas Pricing Downward Adjustment, which is capped at approximately $23.9 million. In addition to the Gas Pricing Downward Adjustment, the Purchase Price is subject to further adjustments, as provided in the Purchase Agreement, including, among others, adjustments relating to (i) costs and expenses incurred by the Debtors in connection with the maintenance of the Debtors’ properties before and after the effective date, (ii) changes in the value of certain of our hedging contracts in the event of their early termination prior to the closing, (iii) gas imbalance volumes, (iv) environmental conditions, if any, (v) title defects and benefits, if any, (vi) taxes, (vii) proceeds of production before and after the effective date, (viii) unsold inventory as of the effective date, and (ix) prepaid items. The proceeds from the sale of the Equity Interests will be used to substantially reduce our indebtedness under the Revolving Facility. We currently have approximately $226.5 million of outstanding principal under our Revolving Facility which is substantially in excess of the proceeds expected to be received pursuant to the Purchase Agreement.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP 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 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

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quantity and value of our reserves. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. Significant changes to the way we report reserves are expected for the year ended December 31, 2009 as a result of the new rules issued by the SEC (see “Recently Issued Accounting Pronouncements (Not Yet Adopted)”). These changes are expected to impact the following calculations.

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, 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 September 30, 2009, but the average prices for oil, natural gas liquids (“NGL”) and natural gas at the balance sheet date as of September 30, 2009 were $70.61 per barrel, $42.37 per barrel and $3.30 per MMBtu, respectively. We were not required to record an impairment during the third 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 and third quarters of 2009. If the 2008 and 2009 impairments had not been taken, our depletion rate would have been approximately $7.48 per Mcfe as compared to $2.45 per Mcfe reported for the three months ended September 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 $24.5 million, net of tax, at September 30, 2009. A 10% increase in prices would have increased our cushion by approximately 144%, net of tax. A 10% decrease in prices would have eliminated the cushion and resulted in an impairment of approximately $3.3 million, net of tax. Therefore, should prices decline in the fourth quarter of 2009, due to either market conditions or as a result of the adoption of the modernization of reserves rules applicable at December 31, 2009, the potential for an impairment at year-end 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 September 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 33% 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 September 30, 2009 by approximately 80%.

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Nature of Critical Estimate Item: Asset Retirement Obligations (“ARO”) - We have certain obligations to remove tangible equipment and restore land at the end of oil and natural gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells. In accordance with FASB ASC 410-20, 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 FASB ASC 740, 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 FASB ASC 740-10-25, Income Taxes, we have recorded a liability of $0.1 million associated with uncertain tax positions. FASB ASC 740-10-25 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)

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that a tax position will be sustained upon examination, including resolution of 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, second and third 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 nine months of 2009, we recorded a valuation allowance of approximately $36.0 million. 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 have periodically entered into 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 FASB ASC 815-10, Derivatives and Hedging, 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 September 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 $0.5 million. Had we applied cash flow hedge accounting treatment to all of our derivative contracts outstanding at September 30, 2009, our net loss to common stockholders for the nine months would have been approximately $61.2 million, or $2.34 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 nine months ended September 30, 2009 of $94.7 million, or $3.50 basic and diluted loss per share.

Results of Operations

This section includes discussion of our results of operations for the three and nine months ended September 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.

Third Quarter 2009 Compared to the Third Quarter 2008

Revenue and Production

Total revenue decreased significantly from the third quarter of 2008 to the comparable 2009 period. Excluding the effects of derivative activity, revenue decreased 77% from the third quarter of 2008 to the comparable 2009 period. For the three months ended September 30, 2009 and 2008, our product mix contributed the following percentages of revenue and production volumes:


	REVENUE (1)				REVENUE (2)				PRODUCTION VOLUMES (MCFE)
	Three Months Ended September 30,
	2009		2008		2009		2008		2009		2008
Natural gas	59	%	73	%	55	%	61	%	68	%	70	%
Natural gas liquids	18	%	8	%	20	%	20	%	22	%	20	%
Crude oil and condensate	23	%	19	%	25	%	19	%	10	%	10	%

Total	100	%	100	%	100	%	100	%	100	%	100	%

(1) Includes effect of derivative transactions

(2) Excludes effect of derivative transactions

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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				$			%
	September 30,				Increase			Increase
	2009		2008		(Decrease)			(Decrease)
	(in thousands, except prices and percentages)
Production Volumes:
Natural gas (MMcf)	1,795		2,789		(994		)	(36	)%
Natural gas liquids (MBbls)	95		132		(37		)	(28	)%
Crude oil and condensate (MBbls)	46		68		(22		)	(32	)%
Natural gas equivalent (MMcfe)	2,641		3,989		(1,348		)	(34	)%
Average Sales Price(1):
Natural gas ($ per Mcf)(2)	$	3.08	$	9.45	$	(6.37	)	(67	)%
Natural gas liquids ($ per Bbl)	21.55		64.53		(42.98		)	(67	)%
Crude oil and condensate ($ per Bbl)(2)	55.29		122.05		(66.76		)	(55	)%
Natural gas equivalent ($ per Mcfe)(2)	3.85		10.82		(6.97		)	(64	)%
Natural gas equivalent ($ per Mcfe)(3)	4.22		26.73		(22.51		)	(84	)%
Operating Revenue:
Natural gas (2)	$	5,520	$	26,375	$	(20,855	)	(79	)%
Natural gas liquids	2,048		8,516		(6,468		)	(76	)%
Crude oil and condensate (2)	2,557		8,245		(5,688		)	(69	)%
Gain on derivatives	1,011		63,505		(62,494		)	(98	)%
Total revenue	$	11,136	$	106,641	$	(95,505	)	(90	)%

(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 September 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 2009 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 September 30,
	2009	2008

Production Volumes per Day:

Natural gas (MMcf/D)	19.5	30.3

Natural gas liquids (MBbls/D)	1.0	1.4

Oil and condensate (MBbls/D)	0.5	0.7

Natural gas equivalent (MMcfe/D)	28.7	43.4

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 economic recession and oversupply of natural gas in North America led to an unprecedented collapse of oil and natural gas prices, with oil falling by more than $100.00 per barrel and natural gas falling more than $10.00 per

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Mcf from their peaks in July 2008. Although crude oil prices have shown some recovery in late 2009 rising to approximately $80.00 per barrel, natural gas prices have remained weak around $3.00 to $5.00 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 September 30, 2009, natural gas revenue, excluding derivative activity, decreased 79% 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 $9.4 million (based on 2008 comparable period pre-derivative prices). The decrease in average price received, excluding derivative activity, resulted in decreased revenue of approximately $11.4 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 revenue - For the three months ended September 30, 2009, NGL revenue decreased 76% 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 $4.1 million (based on current period production). The decrease in NGL production decreased revenue by approximately $2.4 million (based on 2008 comparable period average prices).

Crude oil and condensate revenue - For the three months ended September 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 September 30, 2009 resulted in a decrease in revenue of approximately $3.1 million (based on current period production). The decrease in oil and condensate production resulted in a decrease in revenue of approximately $2.6 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 and 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 net gain on derivatives for each of the periods indicated and the impact each component had on our realized prices:

	Three Months Ended September 30,
	2009						2008
	$			$ per unit (1)			$			$ per unit (1)
	(in thousands, except per unit prices)

Natural gas derivative contract settlements (Mcf)	$	8,011		$	4.47		$	(5,011	)	$	(1.79	)

Crude oil derivative contract settlements (Bbl)	57			1.25			(7,195		)	(106.50		)

Mark-to-market unrealized change in fair value of gas derivative contracts (Mcf)	(6,937		)	(3.87		)	56,417			20.20

Mark-to-market unrealized change in fair value of oil derivative contracts (Bbl)	(120		)	(2.60		)	19,294			285.61

Gain on derivatives (Mcfe)	$	1,011		$	0.37		$	63,505		$	15.91

(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. In October 2009, the caps on all of our derivative collars for the remaining term of the fourth quarter of 2009 were repurchased such that only the floors remain in place. The cost of this transaction was reimbursed by the Company’s proposed purchaser. Except for this change, we have not entered into any new derivative contracts in recent months and do not expect to for the foreseeable future.

Costs and Operating Expenses

The table below details our expenses:

						2009 Period Compared to 2008 Period
	Three Months Ended					$			%
	September 30,					Increase			Increase
	2009		2008			(Decrease)			(Decrease)
	(in thousands, except percentages)
Oil and natural gas operating expenses	$	3,171	$	4,039		$	(868	)	(21	)%
Severance and ad valorem taxes	324		2,654			(2,330		)	(88	)%
Depletion, depreciation, amortization and accretion:
Oil and natural gas property and equipment	6,459		21,601			(15,142		)	(70	)%
Other assets	165		181			(16		)	(9	)%
ARO accretion	96		92			4			4	%
Impairment of oil and natural gas properties	—		129,520			(129,520		)	(100	)%
General and administrative expenses	5,152		6,380			(1,228		)	(19	)%
Total operating expenses	$	15,367	$	164,467		$	(149,100	)	(91	)%

Other income and expense, net	4,133		2,898			1,235			43	%
Income tax expense (benefit)	42		(20,714		)	20,756			100	%
Preferred stock dividends	—		2,066			(2,066		)	(100	)%

Oil and natural gas operating expenses - Oil and natural gas operating expenses include direct operating costs, repairs and maintenance and workover expenses. Operating expenses for the three months ended September 30, 2009 were 21% lower than operating expenses for the same period in 2008. In addition to lower workover expenses there were reduced costs for saltwater disposal, repairs and maintenance and contract pumping services in the third quarter of 2009 compared to the same period in 2008. Average oil and natural gas operating expenses on a unit-of-production basis were $1.20 per Mcfe and $1.01 per Mcfe for the three months ended September 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 September 30, 2009 was 87% 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 2009. For the three months ended September 30, 2009, severance tax expense was approximately 3.1% of revenue subject to severance taxes compared to 5.8% of revenue subject to severance taxes for the third quarter of 2008. Ad valorem tax expense for the third quarter of 2009 was significantly lower than the third quarter of 2008 due to revising estimated expense for 2009. On an equivalent basis, severance and ad valorem taxes averaged $0.12 per Mcfe and $0.67 per Mcfe for the three months ended September 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 34% lower production volumes in the third quarter of 2009 compared to the third quarter of 2008. Our depletion rate for the three months ended September 30, 2009 was $2.45 per Mcfe, a 55% decrease compared to the third quarter 2008 rate of $5.41 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 third quarter of 2009 was slightly lower than the same period in 2008. Accretion expense associated with our ARO for the three months ended September 30, 2009 increased due to revisions in the ARO liability made during 2008 and the new layers added in 2008 and 2009.

Impairment of oil and natural gas properties — No impairment was required for the third quarter of 2009. At September 30, 2008 we recorded a non-cash full-cost ceiling test impairment of oil and natural gas properties in the amount of $129.5 million ($84.2 million net of tax). The write-down was the result of declines in commodity prices and negative revisions in our proved reserve quantities at year-end 2007 and during 2008.

General and administrative (“G&A”) expenses — G&A expense decreased 19% for the three months ended September 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 51% drop in our staffing levels since September 30, 2008. We also had a decrease in general legal fees in the three months ended September 30, 2009 as compared to the same period of 2008. Partially offsetting these decreases were the costs associated with our financial and strategic alternative process that increased significantly from $1.8 million in the three months ended September 30, 2008 to $2.3 million for the three months ended September 30, 2009. We also had an increase in contract labor costs in 2009. Capitalized G&A costs for third quarter 2009 and 2008 were approximately $0.6 million and $1.5 million, respectively. G&A on a unit-of-production basis for the three months ended September 30, 2009 was $1.95 per Mcfe compared to $1.60 per Mcfe for the comparable 2008 period. G&A on a unit-of-production basis, excluding non-cash share-based compensation costs and bad debt expense, for the three months ended September 30, 2009 averaged $1.88 per Mcfe compared to $1.45 per Mcfe in the same period in 2008.

Other income and expense, net - During the three months ended September 30, 2009, our other income and expense increased primarily due to an increase in interest expense resulting from lower capitalization rates. For the third quarter of 2009, we capitalized less interest due to a 10% lower unproved property base on which we calculate interest expense subject to capitalization.

	Three Months Ended September 30,
	2009			2008
	(in thousands)
Gross interest expense	$	3,303		$	3,470
Less: capitalized interest	(287		)	(655		)
Interest expense, net	$	3,016		$	2,815

Weighted average debt	$	227,234		$	239,913

We recorded amortization of deferred loan costs related to our Revolving Facility during the three months ended September 30, 2008 and none in the third quarter of 2009. We also recorded $1.1 million in Reorganization expense for the three months ended September 30, 2009 as compared to none in the same period in 2008.

Income tax benefit — For the three months ended September 30, 2009, we recorded tax expense of approximately $42,000 related to the valuation allowance established for an alternative minimum tax payment required when we filed our 2005 amended tax return. During the three months ended September 30, 2008, we recorded an income tax benefit of $20.7 million with no valuation allowance.

Preferred stock dividends — Our Board of Directors has not declared quarterly dividends on our Convertible Preferred Stock since October 2008. Such dividends were declared in December 2007, March 2008, June 2008 and September 2008. As a result, there is no dividend expense reported for the three months ended September 30, 2009 compared to $2.1 million for the same period in 2008.

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Loss per share — We reported a net loss for the quarters ended September 30, 2009 and 2008. The loss in the third 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 September 30, 2009 and 2008 were comparable. At September 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.

Nine Months Ended September 30, 2009 Compared to the Nine Months Ended September 30, 2008

Revenue and Production

Excluding the effects of derivative activity, revenues decreased 75% from the first nine months of 2008 to the comparable 2009 period. The Company’s decrease in revenue from the first nine months of 2008 to the comparable 2009 period was primarily due to (1) commodity pricing that was significantly lower than first nine 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. These declines were partially mitigated by net gains from derivative activity in the current year period compared to net losses in the prior year period. Our product mix contributed the following percentages of revenues and production volumes:

	REVENUES (1)				REVENUES (2)				PRODUCTION VOLUMES (MCFE)
	Nine Months ended September 30,
	2009		2008		2009		2008		2009		2008
Natural gas	73	%	66	%	60	%	63	%	68	%	70	%
Natural gas liquids	13	%	21	%	18	%	18	%	21	%	20	%
Crude oil and condensate	14	%	13	%	22	%	19	%	11	%	10	%

Total	100	%	100	%	100	%	100	%	100	%	100	%

(1) Includes effect of derivative transactions

(2) Excludes effect of derivative transactions

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

						2009 Period Compared
						to 2008 Period
	Nine Months Ended					$			%
	September 30,					Increase			Increase
	2009		2008			(Decrease)			(Decrease)
	(in thousands, except prices and percentages)
Production Volumes:
Natural gas (MMcf)	5,971		9,604			(3,633		)	(38	)%
Natural gas liquids (MBbls)	299		449			(150		)	(33	)%
Crude oil and condensate (MBbls)	163		230			(67		)	(29	)%
Natural gas equivalent (MMcfe)	8,743		13,678			(4,935		)	(36	)%
Average Sales Price(1):
Natural gas ($ per Mcf)(2)	$	3.52	$	9.17		$	(5.65	)	(62	)%
Natural gas liquids ($ per Bbl)	20.72		55.35			(34.63		)	(63	)%
Crude oil and condensate ($ per Bbl)(2)	46.32		114.41			(68.09		)	(60	)%
Natural gas equivalent ($ per Mcfe)(2)	3.97		10.18			(6.21		)	(61	)%
Natural gas equivalent ($ per Mcfe)(3)	5.37		8.54			(3.17		)	(37	)%
Operating Revenue:
Natural gas (2)	$	21,042	$	88,069		$	(67,027	)	(76	)%
Natural gas liquids	6,186		24,861			(18,675		)	(75	)%
Crude oil and condensate (2)	7,569		26,282			(18,713		)	(71	)%
Gain (loss) on derivatives	12,188		(22,452		)	34,640				*
Total revenue	$	46,985	$	116,760		$	(69,775	)	(60	)%

(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 nine months ended September 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 2009 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 Nine Months Ended September 30,
	2009	2008
Production Volumes per Day:
Natural gas (MMcf/D)	21.9	35.1
Natural gas liquids (MBbls/D)	1.1	1.6
Oil and condensate (MBbls/D)	0.6	0.8
Natural gas equivalent (MMcfe/D)	32.0	49.9

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 economic recession and oversupply of natural gas in North America led to an unprecedented collapse of 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 late 2009 rising to approximately $80.00 per barrel, natural gas prices have remained weak around $3.00 to $5.00 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 first nine months 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 $33.3 million (based on 2008 comparable period pre-derivative prices). The decrease in average price received resulted in decreased revenue of approximately $33.7 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 nine months ended September 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 $8.3 million (based on 2008 comparable period prices). Lower average realized NGL prices for the nine months ended September 30, 2009 resulted in decreased revenue of approximately $10.3 million (based on current period production).

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Crude oil and condensate revenue - For the nine months ended September 30, 2009, oil and condensate sales revenue, excluding derivative activity, decreased 71% 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 $11.1 million (based on current period production). The decrease in oil and condensate production resulted in a decrease in revenue of approximately $7.6 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 and 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.

	Nine Months Ended September 30,
	2009						2008
	$			$ per unit (1)			$			$ per unit(1)
	(in thousands, except per unit prices)

Natural gas contract settlements (Mcf)	$	20,880		$	3.50		$	(11,381	)	$	(1.18	)

Crude oil contract settlements (Bbl)	1,064			6.52			(19,473		)	(84.77		)

Mark-to-market reversal of prior period unrealized change in fair value of gas derivative contracts (Mcf)	(13,390		)	(2.24		)	(2,626		)	(0.27		)

Mark-to-market unrealized change in fair value of gas derivative contracts (Mcf)	5,557			0.93			2,565			0.26

Mark-to-market reversal of prior period unrealized change in fair value of oil derivative contracts (Bbl)	(2,015		)	(12.34		)	14,954			65.10

Mark-to-market unrealized change in fair value of oil derivative contracts (Bbl)	92			0.58			(6,491		)	(28.25		)

Gain (loss) on derivatives (Mcfe)	$	12,188		$	1.40		$	(22,452	)	$	(1.64	)

(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. In October 2009, the caps on all of our derivative collars for the remaining term of the fourth quarter of 2009 were repurchased such that only the floors remain in place. The cost of this transaction was reimbursed by the Company’s proposed purchaser. Except for this change, we have not entered into any new derivative contracts in recent months and do not expect to for the foreseeable future. Our 2008 derivative position exceeded our 2008 production exposing us to greater cash losses and risk of losses during that period.

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Costs and Operating Expenses

The table below details our expenses:

						2009 Period Compared
						to 2008 Period
	Nine Months Ended					$			%
	September 30,					Increase			Increase
	2009		2008			(Decrease)			(Decrease)
	(in thousands, except percentages)
Oil and natural gas operating expenses	$	10,820	$	12,452		$	(1,632	)	(13	)%
Severance and ad valorem taxes	2,672		8,136			(5,464		)	(67	)%
Depletion, depreciation, amortization and accretion:
Oil and gas property and equipment	23,548		69,926			(46,378		)	(66	)%
Other assets	512		558			(46		)	(8	)%
ARO accretion	288		283			5			2	%
Impairment of oil and natural gas properties	78,254		129,520			(51,266		)	(40	)%
General and administrative expenses	14,666		15,592			(926		)	(6	)%
Total operating expenses	$	130,760	$	236,467		$	(105,707	)	(45	)%

Other income and expense, net	$	10,898	$	9,783		$	1,115		11	%
Income tax expense (benefit)	42		(45,478		)	45,520			100	%
Preferred stock dividends	—		6,199			(6,199		)	(100	)%

Oil and natural gas operating expenses - For the nine months ended September 30, 2009, operating expenses decreased as compared to the same period of 2008 due primarily to decreased costs associated with saltwater disposal, repairs and maintenance and compressor rent, partially offset by increased costs for well workover activity. On an equivalent Mcfe basis we had an overall increase in our average oil and natural gas operating expenses on a unit-of-production basis, which were $1.24 per Mcfe for the nine months ended September 30, 2009 as compared to $0.91 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 nine months ended September 30, 2009, severance and ad valorem taxes decreased significantly from the first nine months of 2008. Severance tax expense for the nine months ended September 30, 2009 was 81% lower than the prior year period due primarily to lower revenue and 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 nine months ended September 30, 2009, severance tax expense was approximately 4.5% of revenue subject to severance taxes compared to 5.8% of revenue subject to severance taxes for the first nine months of 2008. Ad valorem tax expense for the first nine months of 2009 was significantly higher than the prior year because our 2007 year-end estimates were too high which impacted 2008 offsetting normal expense. On an equivalent basis, severance and ad valorem taxes averaged $0.31 per Mcfe and $0.59 per Mcfe for the nine months ended September 30, 2009 and 2008, respectively.

DD&A and accretion - Depletion on our oil and natural gas properties decreased for the first nine months of 2009 compared to the same period of 2008 due to a decrease in our unit-of-production depletion rate and lower production volumes, which is discussed under “Revenue and Production” above. The depletion rate decreased from $5.11 per Mcfe in the first nine months of 2008 to $2.69 per Mcfe in the first nine months of 2009, primarily as a result of the impairments of our oil and natural gas properties taken during 2008 and the first quarter of 2009. Depreciation of furniture and fixtures and accretion expense for the first nine months of 2009 were slightly lower than the first nine months of 2008.

Impairment of oil and natural gas properties - We recorded a net non-cash ceiling test impairment of $78.3 million, net of tax, during the quarter ended March 31, 2009, as discussed in Note 3 to the consolidated financial statements, and have not recorded any further impairments in the second and third quarters of 2009. At September 30, 2008 we recorded a non-cash full-cost ceiling test impairment of oil and natural gas properties in the amount of $129.5 million ($84.2 million, net of tax), which was the result of declines in commodity prices and negative revisions in our proved reserve quantities at year-end 2007 and during 2008. No such impairment was reported in the first and second quarters of 2008.

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G&A expense - G&A expense for the first nine months of 2009 was 6% lower than the same period of 2008. We had two primary offsetting items that contributed to the variance. We recorded an increase in costs of our financial and strategic alternatives process from $2.1 million in the nine months of 2008 to $5.9 million in the comparable period of 2009. This increase was offset by a $6.0 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 nine months 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 nine months of 2009 were lower at $2.0 million as compared to $3.6 million for the comparable prior year period. G&A expense on a unit-of-production basis for the nine months ended September 30, 2009 increased to $1.68 per Mcfe as compared to $1.14 per Mcfe for the comparable 2008 period. G&A expense on a unit-of-production basis, excluding non-cash share-based compensation costs and bad debt expense, for the nine months ended September 30, 2009 also increased due to lower production volumes, averaging $1.58 per Mcfe as compared to $0.99 per Mcfe for the comparable 2008 period.

Other income and expense, net - During the nine months ended September 30, 2009, other income and expense in total was higher than the same period of 2008 as a result of amortization of deferred loan costs and Reorganization expense. The amortization of deferred loan costs in 2009 was higher than 2008 due to the acceleration of amortization of those capitalized costs resulting from the change in maturity date of the Revolving Facility. We also recorded $1.1 million in Reorganization expense in the three months ended September 30, 2009 as compared to none in 2008.

Gross interest expense in 2008 was higher than 2009 due to higher outstanding debt balances. For the first nine months of 2009, only 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 to our weighted average debt balance.

	For the Nine Months Ended September 30,
	2009			2008
	(in thousands)
Gross interest expense	$	9,087		$	11,368
Less: capitalized interest	(759		)	(2,045		)
Interest expense, net	$	8,328		$	9,323

Weighted average debt	$	232,562		$	246,825

We recorded lower interest income in the first nine months of 2009 as compared to the first nine months of 2008. During the nine months ended September 30, 2008, we recorded a gain on ARO settlements of approximately $82,700.

Income tax expense - For the nine months ended September 30, 2009, we recorded tax expense of approximately $42,000 related to the valuation allowance established for an alternative minimum tax payment required when we filed our 2005 amended tax return. We did not report a tax benefit for the nine months ended September 30, 2009 because we fully provided for additions to our deferred tax asset with a valuation allowance during the period. During the nine months ended September 30, 2008, we recorded an income tax benefit of $45.4 million with no valuation allowance.

Preferred stock dividends — Our Board of Directors declared dividends on our Convertible Preferred Stock in March, June and September 2008 and none in 2009.

Loss per share - For the first nine months 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 the impairment of oil and natural gas properties of $129.5 million

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($84.2 million, net of tax) and derivative losses of approximately $22.5 million. Basic weighted average shares outstanding for the nine months ended September 30, 2009 were comparable to the prior year. We excluded approximately 8.7 million shares of if-converted common stock attributable to our Convertible 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 nine months ended September 30, 2009 or 2008.

Liquidity and Capital Resources

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.

Historically, our primary ongoing source of capital was the cash flow generated from our operating activities. 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. In the past, we have attempted to mitigate 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. We routinely adjust capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, and cash flow. We typically have funded acquisitions from borrowings under our credit 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. In the past, we have also used proceeds of asset divestitures to supplement our cash flows and reduce outstanding debt.

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, made 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 remained weak in 2009. In 2009, our capital expenditures have been and will continue to be impacted by our liquidity issues and our Chapter 11 Cases, which impose significant constraints on our capital expenditures. In the past we have supplemented shortfalls in our primary resources of capital with borrowings under our Fourth Amended and Restated Credit Agreement (as amended, the “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 were due and payable on September 30, 2009 to the Lenders (defined below). Our primary focus in 2009 has been capital preservation and resolving the uncertainty and liquidity challenges we faced, but continued depressed economic conditions and the deteriorating commodity prices of late 2008 and 2009 have made this difficult. Additionally these conditions were factors in our borrowing base redetermination and the change in the maturity date of our entire outstanding debt balance. We failed to make the required payments to our Lenders and are in default under our Revolving Facility and as a result, we filed for bankruptcy protection October 1, 2009. We intend to operate our business as debtor-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. We intend to use cash flow from operations to provide working capital and financial resources necessary to allow business operations to continue as normal, including meeting obligations to employees and certain vendors, customers and others as we proceed through the Chapter 11 Cases.

We had cash and cash equivalents at September 30, 2009 of $13.4 million consisting primarily of short-term money market investments, as compared to $8.5 million at December 31, 2008. Our working capital deficit was $206.4 million at September 30, 2009, as compared to a working capital deficit of $203.3 million at

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December 31, 2008. At September 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 Nine Months Ended September 30,
	2009			2008
	(in thousands)
Net Cash Provided By Operating Activities	$	26,375		$	77,207

Net Cash Used In Investing Activities	(8,901		)	(41,449		)

Net Cash Used In Financing Activities	(12,500		)	(27,199		)

Net Cash Provided By Operating Activities - The decrease in cash flows provided by operating activities for the nine months 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 $6.4 million in the first nine months of 2009 as compared to $11.7 million in the same period of 2008.

Net Cash Used In Investing Activities - We spent approximately $11.1 million during the first nine months of 2009, including $2.8 million on our drilling and operating program. We drilled 4 wells in the first nine months of 2009, three of which were apparent successes. Leasehold and geological and geophysical activities accounted for expenditures of $8.3 million through September 30, 2009. During the first nine months of 2008, we spent $46.7 million on our drilling and operating program. We drilled 20 wells in the first nine months of 2008, 19 of which were apparent successes. Leasehold and geological and geophysical activities accounted for expenditures of $3.8 million through September 30, 2008. There were also minimal capital expenditures associated with computer hardware, office equipment and other miscellaneous capital charges. During the nine months ended September 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 $19.2 million.

Due to the overhedged position in 2008 and 2009, 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. For the nine months ended September 30, 2009, approximately 3% of our natural gas settlements are represented by the $0.7 million of speculative settlements in this section of the statement of cash flows. The remainder is located in net cash provided by operating activities. For the nine months ended September 30, 2008, approximately 45% of our oil settlements and 19% of our natural gas settlements are represented by the $10.9 million of speculative settlements in this section of the statement of cash flows. The remainder is located in net cash provided by operating activities.

Net Cash Used In Financing Activities - During the nine months ended September 30, 2009, we repaid $12.5 million under our Revolving Facility. In the comparable period of 2008, we repaid $21.0 million using proceeds from our asset sales. We also paid quarterly dividends on our preferred stock in January, April and July 2008, but none in 2009.

Revolving Facility

On January 30, 2007, we entered into the Revolving Facility with Union Bank of California (“UBOC”), as administrative agent and issuing lender, and the other lenders party thereto (together with UBOC, the “Lenders”), in favor of the Company and certain of its wholly-owned subsidiaries in an amount equal to $750 million. The Revolving Facility had a letter of credit sub-limit of $20 million. The Revolving Facility was originally scheduled to mature on January 31, 2011. 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 as a result of the Amended Consent (defined below).

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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.

At September 30, 2009, borrowings under the Revolving Facility bore interest at Prime plus an applicable margin of 2.50%. At September 30, 2009, the interest rate applied to our outstanding borrowings was 5.75%. As of September 30, 2009, we had $226.5 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.

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 our financial and strategic alternatives process:

· 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.

· 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

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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.

· 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.

· On August 31, 2009, the Company entered into Amendment No. 9 which changed the maturity date of the Revolving Facility from August 31, 2009 to September 30, 2009.

On September 30, 2009 all obligations under the Revolving Facility became automatically and immediately due and payable. We failed to make the payment due under the Revolving Facility on or before September 30, 2009 which has resulted in an event of default under the Revolving Facility. As a result, we filed for bankruptcy protection on October 1, 2009. The filing of the Chapter 11 Cases constitutes an additional event of default under our Revolving Facility. The total amount of principal, fees and interest outstanding under the Revolving Facility was approximately $227.6 million as of the Filing Date. However, the ability of the secured creditors to seek remedies to enforce their rights under the Revolving Facility is automatically stayed as a result of the filing of the Chapter 11 Cases. The automatic stay invoked by the filing of the Chapter 11 Cases effectively precludes any actions by our secured creditors to collect, assert, or recover a claim against the Debtors, subject to the applicable provisions of the Bankruptcy Code and orders granted by the Bankruptcy Court.

In connection with the Plan and to expedite the restructuring and reorganization of the Debtors as contemplated in the Purchase Agreement, we and the lenders to our Revolving Facility (the “Supporting Lenders”) who hold at least two-thirds of the outstanding principal amount pursuant to the Revolving Facility

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and who constitute more than one-half of the number of lenders under the Revolving Facility entered into the Plan Support Agreement dated as of September 30, 2009 which contains as exhibits a draft of the Plan and a draft of the Disclosure Statement. The Plan Support Agreement requires the Supporting Lenders to (i) vote in favor of and support the Plan, (ii) vote against and not support any restructuring or reorganization that is not consistent with the Plan, and (iii) not (a) seek, solicit, support or encourage any other restructuring plan, (b) object to the Disclosure Statement or the solicitation of votes for the Plan or support any objection by any third party, or (c) take any action that is inconsistent with, or that would materially delay or obstruct the proposed solicitation, confirmation or consummation of, the Plan.

The support of the Supporting Lenders under the Plan Support Agreement will terminate under certain circumstances, including among others, if (i) the sum of certain proposed adjustments to the Purchase Price with respect to title defects, environmental matters, retained properties and casualty losses exceeds $5 million, (ii) the sum of certain allowed administrative and priority claims exceeds the specified reserve for administrative and priority claims, (iii) the Debtors file a plan of reorganization that is different from the Plan or shall modify or amend the Plan in any material respect without the written consent of the Administrative Agent, (iv) the Bankruptcy Court enters a cash collateral order or budget without the written consent of the required lenders that is materially different from those agreed upon by the Supporting Lenders and the Debtors, (v) the Plan shall not have been confirmed by the Bankruptcy Court in accordance with its terms within one hundred and five (105) days of the Filing Date, (vi) we shall withdraw or revoke the Plan or shall publicly announce its intention not to pursue confirmation of the Plan, (vii) a trustee shall have been appointed in any of the Chapter 11 Cases, any of the Chapter 11 Cases shall have been converted to cases under Chapter 7 of the Bankruptcy Code or any of the Chapter 11 Cases shall have been dismissed by order of the Bankruptcy Court, or (viii) the Plan shall not have been substantially consummated in accordance with its terms within one hundred twenty (120) days of the Filing Date.

The proceeds from the sale of the Equity Interests will be used to substantially reduce our indebtedness under the Revolving Facility. We currently have approximately $226.5 million of outstanding principal under our Revolving Facility which is substantially in excess of the proceeds expected to be received pursuant to the Purchase Agreement.

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. In light of the actions taken by the NASDAQ in October 2009 and our filing of the Chapter 11 Cases, we do not expect to utilize this registration statement.

Convertible Preferred Stock

We completed the public offering of 2,875,000 shares of Convertible Preferred Stock in January 2007.

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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 has not declared a dividend since the third quarter of 2008 due to our current lack of liquidity and the Chapter 11 Cases. Cumulative dividends in arrears at September 30, 2009 amounted to $7.9 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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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.

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:

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· 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.

Chapter 11 Cases. We advise investors of our strong belief that it is likely that there will be no value for the holders of our Convertible Preferred Stock in the Chapter 11 Cases and that the Plan does not currently contemplate such holders’ receiving any recovery absent a substantially higher and better offer for the Equity Interests that is sufficient to pay our secured and unsecured creditors in full (and with respect to the common stock to pay the liquidation preference on the Convertible Preferred Stock). In this regard, stockholders of a company in Chapter 11 generally receive value only if all claims of the company’s secured and unsecured creditors are fully satisfied. In this case and based on the expected proceeds from the sale of the Equity Interests which is substantially less than the amount our secured and unsecured creditors are owed, we strongly believe all such secured and unsecured claims will not be fully satisfied, leading to our belief that the holders of our Convertible Preferred Stock and common stock will receive no value for their interests.

Off Balance Sheet Arrangements

We currently do not have any off balance sheet arrangements.

Fair Value Measurements

Effective January 1, 2008, we partially adopted FASB ASC 820, 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 FASB ASC 820 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 FASB ASC 820-10-15, Fair Value Measurements and Disclosure — Scope and Scope Exceptions, which delayed the effective date of FASB ASC 820 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 FASB ASC 820 to our AROs on January 1, 2009.

FASB ASC 820 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.

FASB ASC 820 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 FASB ASC 820 are as follows:

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· 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.

· 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 FASB ASC 820 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

In the past, we have utilized 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. 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. In October 2009, the caps on all of our derivative collars for the remaining term of the fourth quarter of 2009 were repurchased such that only the floors remain in place. The cost of this transaction was reimbursed by the Company’s proposed purchaser. Except for this change, we have not entered into any new derivative contracts in recent months and do not expect to for the foreseeable future..

All of these price-risk management transactions are considered derivative instruments and accounted for in accordance with FASB ASC 815-10. 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

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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 September 30, 2009.

	(in thousands)
Fair value of contracts outstanding at December 31, 2008	$	15,407
Contracts realized or otherwise settled during the period	21,944
Fair value at September 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	(31,700		)
Fair value of contracts outstanding at September 30, 2009	$	5,651

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

	Fair Value of Contracts at September 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	5,651		—		—		—		5,651
Liability	—		—		—		—		—
Prices based on models and other valuation methods:	—		—		—		—		—
Total	$	5,651	$	—	$	—	$	—	$	5,651

Tax Matters

At September 30, 2009, we had cumulative net operating loss carryforwards (“NOLs”) for federal and state income tax purposes of approximately $199.7 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 2029. In addition to the deferred tax assets associated with NOLs discussed above, we have additional net deferred tax assets of approximately $73.7 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 Chapter 11 Cases, 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 September 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.

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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 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. 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.

Additionally, the consummation of the Plan of Reorganization that we filed in connection with the Chapter 11 Cases will likely result in further limitations on our ability to fully utilize our NOLs.

FASB ASC 740-10-25 provides guidance on recognition and measurement of uncertainties in income taxes. FASB ASC 740-10-25 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. We have recorded our FASB ASC 740-10-25 liability of approximately $0.1 million under long term liabilities on the balance sheet and there has been no change since December 31, 2008. See Notes 3 and 8 to our consolidated financial statements.

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 September 2009, the FASB issued an exposure draft of proposed Accounting Standards Update (“ASU”) entitled Oil and Gas Reserve Estimation and Disclosures. This proposed ASU would amend the FASB accounting standards to align FASB ASC 932, Extractive Activities — Oil and Gas with all of the aforementioned new SEC requirements. This proposal is expected to become an issued accounting update within the last quarter of 2009 with an effective date for annual reports for fiscal years ending on or after

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December 15, 2009. We are currently assessing the impact of this new authoritative accounting guidance on our consolidated financial statements.

In June 2009, the FASB issued guidance which amends the consolidation guidance applicable to variable interest entities. This guidance is included in FASB ASC 810, Consolidation. The amendments significantly reduce the previously required quantitative consolidation analysis, and require ongoing reassessments of whether a company is the primary beneficiary of a variable interest entity. This new guidance 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. We do not currently expect the adoption of the new guidance in FASB ASC 810 to impact our consolidated financial statements.

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 September 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 $1.2 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 January 2009 borrowing base redetermination that resulted in our filing for bankruptcy protection. The continued credit crisis and related turmoil in the global financial system and economic recession in the U.S. has created financial challenges that have prohibited our ability to access credit markets. We will continue to monitor our liquidity as we continue to pursue the consummation of our Plan of Reorganization filed in connection with our Chapter 11 Cases.

As of December 31, 2008 and September 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 September 30, 2009 as provided by Amendment No. 9, 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 September 30, 2009:

Transaction
Date

Transaction
Type (1)

Beginning

Ending

Price
Per Unit

Volumes Per
Day

Fair Value
Outstanding as of
September 30, 2009

(in thousands)

Natural Gas (2):

04/07

Collar

01/01/09

12/31/09

$7.75-$10.00

10,000 MMBtu

2,778

10/07

Collar

01/01/09

12/31/09

$7.75-$10.08

10,000 MMBtu

2,779

Crude Oil (3):

10/07

Collar

01/01/09

12/31/09

$70.00-$93.55

300 Bbl

EDGE PETROLEUM CORP 10-Q