EPEX Edge Petroleum Corp (MM)

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EDGE PETROLEUM CORPORATION Index to Consolidated Financial Statements and Supplementary Information

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

Commission file number: 0-22149

EDGE PETROLEUM CORPORATION
(Exact Name of Registrant as Specified in Its Charter)

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

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         Securities registered pursuant to Section 12(b) of the Act:

         Securities registered pursuant to Section 12(g) of the Act: None

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         Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  o  Yes     ý  No

         Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  o  Yes     ý  No

         Indicate by check mark 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.  ý  Yes     o  No

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ý

         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.

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

         As of June 30, 2008, the aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $144.1 million (based on a value of $5.39 per share, the closing price of the Common Stock as quoted by The NASDAQ Global Select Market on such date).

         As of March 12, 2009, 28,836,927 shares of Common Stock, par value $0.01 per share, were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

         Portions of the definitive proxy statement for the registrant's 2009 Annual Meeting of Shareholders, to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, are incorporated by reference into Part III of this report.

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EDGE PETROLEUM CORPORATION

         Unless otherwise indicated by the context, references herein to the "Company", "Edge", "we", "our" or "us" mean Edge Petroleum Corporation, a Delaware corporation, and its corporate and partnership subsidiaries and predecessors. Certain terms used herein relating to the oil and natural gas industry are defined in ITEMS 1 AND 2. "BUSINESS AND PROPERTIES— CERTAIN DEFINITIONS."

FORWARD LOOKING INFORMATION

        The information contained in this Annual Report on Form 10-K includes certain forward-looking statements. The words "may," "will," "expect," "anticipate," "believe," "continue," "estimate," "project," "intend," and similar expressions used in this Form 10-K 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. For a discussion of the risks which, among others, may affect our financial condition and results of operations please see our risk factors set forth under ITEM 1A. "RISK FACTORS" of this Annual Report.

AVAILABLE INFORMATION

        Our website address is www.edgepet.com . We make our website content available for information purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. We make available on this website under "Investor Relations—SEC Filings," free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. The SEC also maintains a website at www.sec.gov that contains reports, proxy statements and other information regarding SEC registrants, including us.

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PART I

ITEMS 1 AND 2.    BUSINESS AND PROPERTIES

Overview & History

        Edge Petroleum Corporation is an independent oil and natural gas company engaged in the exploration, development, acquisition and production of crude oil and natural gas properties from select onshore basins in the United States. Edge was founded in 1983 as a private company and went public in 1997. We have evolved over time from a prospect generation organization focused on high-risk, high-reward exploration projects to a team-driven organization focused on a balanced program of exploration, exploitation, 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 (more fully discussed below) and have subsequently expanded this process to include a further evaluation of both our financial and strategic alternatives in late 2008 and continuing into 2009. Our current primary focus is on capital preservation and resolving the uncertainty and challenges we face.

Recent Developments

        At year-end 2008, our net proved reserves were 124.1 Bcfe, comprised of 89.6 billion cubic feet of natural gas, 3.5 million barrels of natural gas liquids and 2.3 million barrels of crude oil and condensate. Natural gas and natural gas liquids accounted for approximately 89% of those proved reserves. Approximately 79% of our total proved reserves were developed as of year-end 2008 and they were all located onshore, in the United States. Our reduced drilling program resulted in 25 gross (8.74 net) apparent successes out of 27 gross (9.95 net) wells drilled in 2008. During 2008, we focused a great deal of our efforts on our financial and strategic alternatives process (see below). In January 2009, the lenders ("Lenders") to our Fourth Amended and Restated Credit Agreement (as amended, the "Revolving Facility") completed their borrowing base redetermination, which resulted in a reduction of our borrowing base to $125 million, thereby eliminating availability for additional borrowing for the near future and creating a substantial borrowing base deficiency of $114 million (the "Deficiency"), which is described below and in Note 11 to our consolidated financial statements. This Deficiency was largely the result of lower commodity prices and increased costs which impacted the reserve calculation used to redetermine our borrowing base along with our inability to replace and increase our reserves over the last year.

        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. On February 7, 2008, we provided an update on the strategic alternative process and publicly announced that we would implement a process to explore a merger or sale of the Company. As a result of the strategic alternatives process, on July 15, 2008, we and Chaparral Energy, Inc. ("Chaparral"), a privately held company, announced that we had entered into a definitive merger agreement that provided for Chaparral to acquire Edge in an all-stock transaction. To provide additional funding for the transaction, Chaparral expected to sell 1.5 million shares of its Series B convertible preferred stock, par value $0.01 per share for $150 million in a private sale to Magnetar Financial LLC, on behalf of itself and one or more of its affiliates and assigns (collectively, "Magnetar").

        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. 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. As

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a result, after consultation with our legal and financial advisors, our Board of Directors approved a merger termination agreement with Chaparral and a termination and settlement agreement among us, Chaparral and Magnetar. Pursuant to the termination agreements, Magnetar reimbursed Chaparral $5.0 million for certain expenses, of which $1.5 million was paid to us at Chaparral's direction, of which we paid $0.3 million to our then-financial advisor, Merrill Lynch.

        During January 2009, we announced that the Lenders to our Revolving Facility had completed their borrowing base redetermination and reduced our borrowing base to $125 million, resulting in the Deficiency. Pursuant to the terms of the Revolving Facility, we elected to prepay the Deficiency in six equal monthly installments, with the first $19 million installment being due on February 9, 2009. 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 agreed to prepay $5.0 million of our 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 the prepayments to be applied on a pro rata basis to reduce the remaining six $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 provides, among other things, (1) that we will 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 will be an event of default (i) if we fail 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 are in default under or our hedging arrangements have been terminated or cease to be effective without the prior written consent of our Lenders, (3) that our advances under the Revolving Facility will 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% as of March 16, 2009), (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 eliminates the six $19 million deficiency payments which were contemplated by the February Consent and the March Consent. To comply with the terms of the Amended Consent, we anticipate that we will need to (i) sell select individual assets prior to May 31, 2009 to enable us to make the $25 million payment which is due on May 31, 2009, and/or (ii) negotiate a commitment letter with a new lender or group of lenders prior to May 15, 2009 in an amount sufficient to repay all of our obligations under the Revolving Facility on or before June 30, 2009, and/or (iii) have negotiated the sale, merger or other business combination involving us which

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results in the repayment of all of our obligations under the Revolving Facility prior to May 15, 2009 and to have closed such transaction on or before June 30, 2009. The Amended Consent limits the making of capital expenditures and we anticipate a severe curtailment of our drilling plans and other capital expenditures in 2009.

        If we breach any of the provisions of the Amended Consent or the Revolving Facility, our Lenders will be entitled to declare an event of default, at which point the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, would become immediately due and payable. In any event, the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, will be payable on June 30, 2009 unless earlier paid or a further extension with respect to payment is negotiated with our Lenders. Our Lenders may take action to enforce their rights with respect to the outstanding obligations under the Revolving Facility. Because substantially all of our assets are pledged as collateral under the Revolving Facility, if our Lenders declare an event of default, they would be entitled to foreclose on and take possession of our assets. In such an event, we may be forced to liquidate or to otherwise seek protection under Chapter 11 of the U.S. Bankruptcy Code. These matters, as well as the other risk factors related to our liquidity and financial position raise substantial doubt as to our ability to continue as a going concern. See ITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS —LIQUIDITY AND CAPITAL RESOURCES— REVOLVING FACILITY." With respect to our compliance with the Amended Consent, there can be no assurance that we will be able to further negotiate the terms of the Amended Consent or negotiate a further restructuring of the related indebtedness or that we will be able to make any required payments when they become due. Moreover, there can be no assurance that we will be successful in our efforts to comply with the terms of the Amended Consent, including our ongoing efforts to evaluate and assess our various financial and strategic alternatives (which may include the sale of some or all of our assets, a merger or other business combination involving the Company, or the restructuring or recapitalization of the Company). If such efforts are not successful, we may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

        Going Concern —In addition to the Deficiency under our Revolving Facility, the capital expenditures required to maintain and/or grow production and reserves are substantial. Our stock price has significantly declined over the past year which makes it more difficult to obtain equity financing on acceptable terms to address our liquidity issues. In addition, we are reporting negative working capital at December 31, 2008 and a third consecutive year of net losses for the year ended December 31, 2008, which is largely the result of impairments of our oil and natural gas properties. Therefore, there is substantial doubt as to our ability to continue as a going concern for a period longer than the current fiscal year. Our ability to continue as a going concern is dependent upon the success of our financial and strategic alternatives process, which may include the sale of some or all of our assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company. Until the possible completion of the financial and strategic alternatives process, our future remains uncertain and there can be no assurance that our efforts in this regard will be successful.

        Our consolidated financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which implies we will continue to meet our obligations and continue our operations for the next twelve months. Realization values may be substantially different from carrying values as shown, and our 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. Our independent auditors have included an explanatory paragraph in their report on our consolidated financial statements that raises substantial doubt about our ability to continue as a going concern. See ITEM 8. "FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA— Report of the Independent Registered Accounting Firm."

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Strategy

        In connection with our ongoing financial and strategic alternatives process and due to our liquidity issues resulting from the Deficiency and the related Amended Consent, we will be operating with a reduced capital spending program in 2009 as we continue to pursue the sale of some or all of our assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company. Our strategy is currently to continue under a severely limited capital and operating budget, thereby reducing our normal exploration and development activities as we seek to preserve liquidity and resolve the uncertainty and challenges that we face and pursue various financial and strategic alternatives. We expect to drill three to four wells (0.6 to 1.0, net) during 2009, in south Texas, southeast New Mexico, and in the Arkansas Fayetteville Shale Play, complemented by a recompletion program in south Texas and selected expenditures for land and seismic. We anticipate these activities will result in total capital spending in the range of $15 to $20 million for 2009.

Employees

        As of March 11, 2009, we had 57 full-time and 2 part-time employees. We believe that we have good relationships with our employees. None of our employees is covered by a collective-bargaining agreement. In addition, we utilize the services of independent consultants and contractors to perform various professional services, particularly in the areas of engineering, construction, design, well-site surveillance, permitting and environmental assessment. Field and on-site production operation services, such as pumping, maintenance, dispatching, inspection and testing, are generally provided by independent contractors.

Offices

        We lease executive and corporate office space located at 1301 Travis Street, Suite 2000, Houston, Texas, 77002.

Oil and Natural Gas Reserves

        The Company's reserves decreased in 2008 due to lower commodity prices, production, property sales and revisions to previous estimates. We were unable to replace the production we generated due to our reduced capital spending program and higher drilling and operating costs. However, the decrease was partially offset by extensions and discoveries that resulted from the drilling of 25 gross (8.74 net) apparent successes, recompletion of one well, and the addition of one proved undeveloped ("PUD") location. Revisions to previous estimates during 2008 were primarily due to (1) commodity pricing that was significantly lower than year-end 2007, causing a number of PUD locations to be uneconomic and shortening the economic life of many other properties, (2) results of actual drilling and recompletion operations and updated technical analysis, (3) updates to shrink and differential factors and (4) updated performance (both positive and negative) on existing producing wells. The Company's net ownership in estimated quantities of proved oil and natural gas reserves and the present value of estimated future net cash flows related to such reserves, all of which are located in the continental United States, are summarized below.

        We engaged Ryder Scott Company, L.P. ("Ryder Scott") and W. D. Von Gonten & Co. ("WDVG") to estimate our net proved reserves, projected future production, estimated future net revenue attributable to our proved reserves, and the present value of such estimated future net revenue as of December 31, 2008. Ryder Scott's and WDVG's estimates were based upon a review of production histories and other geologic, economic, ownership and engineering data provided by us. Ryder Scott has independently evaluated our reserves for the past 15 years and WDVG has independently evaluated the reserves we acquired late in 2004 for the past seven years. In estimating the reserve quantities that are economically recoverable, Ryder Scott and WDVG used oil and natural

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gas prices in effect at December 31, 2008 and estimated development and production costs that were in effect during December 2008 without giving effect to hedging activities. In accordance with SEC regulations, no price or cost escalation or reduction was considered by Ryder Scott and WDVG. For further information concerning Ryder Scott and WDVG's estimates of our proved reserves at December 31, 2008, see the summaries of the reserve reports of Ryder Scott and WDVG included as exhibits to this Form 10-K (respectively, the "Ryder Scott Report" and the "WDVG Report"). In accordance with Statement of Financial Accounting Standards ("SFAS") No. 69, Disclosures About Oil and Natural Gas Producing Activities, the present value of estimated future net revenues after income taxes was prepared using constant prices as of the calculation date, discounted at 10% per annum, but is not intended to represent the current market value of the estimated oil and natural gas reserves we owned. For further information concerning the present value of future net revenue from our proved reserves, see Note 23 to our consolidated financial statements. See also ITEM 1A. "RISK FACTORS." The oil and natural gas reserve data included in or incorporated by reference in this document are only estimates and may prove to be inaccurate. The following table reflects a summary of our proved reserve volumes and a reconciliation between estimated future net revenue, before income taxes, attributable to estimated proved reserves, discounted at 10% per annum (the "PV-10 Value") and the standardized measure of discounted future net cash flows.

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(1)

Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods.

(2)

Proved undeveloped reserves are proved reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

(3)

Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, net of estimated future production and development costs, using year-end NYMEX oil and natural gas prices in effect at December 31, 2008, which were $5.71 per MMbtu of natural gas and $44.60 per Bbl of oil. Management believes that the presentation of the PV-10 Value, may be considered a non-GAAP financial measure as defined in Item 10(e) of Regulation S-K, therefore the Company has included this reconciliation of the measure to the most directly comparable GAAP financial measure (standardized measure of discounted future net cash flows). Management believes that the presentation of PV-10 Value provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company may impact the amount of future income taxes to be paid, the use of the pre-tax measure provides greater comparability when evaluating companies. It is relevant and useful to investors for evaluating the relative monetary significance of the Company's oil and natural gas properties.

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Further, investors may utilize the measure as a basis for comparison of the relative size and value of the Company's reserves to other companies. Management also uses this pre-tax measure when assessing the potential return on investment related to its oil and natural gas properties and in evaluating acquisition candidates. The PV-10 Value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of the estimated oil and natural gas reserves owned by the Company. PV-10 Value should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

(4)

As of December 31, 2008, we were not in a tax paying position and therefore income taxes are not applicable to this presentation.

        The reserve data set forth herein represents estimates only. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates, and such revisions may be material. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the present value thereof are based upon certain assumptions, including current prices, production levels and costs that may not be what is actually incurred or realized. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.

        In accordance with SEC regulations, the Ryder Scott Report and the WDVG Report each used year-end oil and natural gas prices in effect at December 31, 2008, adjusted for basis and quality differentials. The prices used in calculating the estimated future net revenue attributable to proved reserves do not necessarily reflect market prices for oil and natural gas production subsequent to December 31, 2008. 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 decline in oil and natural gas prices, with oil prices falling by more than $100.00 per barrel and natural gas prices falling more than $8.00 per Mcf from their peaks in July 2008. There can be no assurance that all of the proved reserves will be produced and sold within the periods indicated, that the assumed prices will actually be realized for such production or that existing contracts will be honored or judicially enforced. Decreases in the assumed commodity prices result in decreases in estimated future net revenue as well as in estimated reserves.

Oil and Natural Gas Reserve Replacement

        Finding and developing sufficient amounts of natural gas and crude oil reserves at economical costs are critical to our long-term success. 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 ability to generate revenues in the future will shrink. This was a factor in our 2008 results, which reflected a 24% lower proved reserve base at year-end. 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. Given the inherent decline of reserves resulting from the production of those reserves, it is important for an exploration and production company to demonstrate a long-term trend of more than offsetting produced volumes with new reserves that will provide for future production. We use the reserve replacement ratio, as defined below, as an indicator of our ability to replenish annual

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production volumes and grow our reserves, thereby providing some information on the sources of future production and income. We believe that reserve replacement is relevant and useful information that is commonly used by analysts, investors and other interested parties in the oil and gas industry as a means of evaluating the operational performance and to a greater extent the prospects of entities engaged in the production and sale of depleting natural resources. These measures are often used as a metric to evaluate an entity's historical track record of replacing the reserves that it has produced. The reserve replacement ratio is calculated by dividing the sum of reserve additions from all sources (revisions, acquisitions, extensions and discoveries) by the actual production for the corresponding period. Additions to our reserves are proven developed and proven undeveloped reserves. Our severely limited drilling program will restrict our ability to add to our reserve base. See ITEM 1A. "RISK FACTORS" . The values for these reserve additions and production are derived directly from the proved reserves table in Note 23 to our consolidated financial statements. Accordingly, we do not use unproved reserve quantities. The reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not consider the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. The ratio does not distinguish between changes in reserve quantities that are developed and those that will require additional time and funding to develop. In that regard, the percentage of reserves that were developed was 79%, 77%, and 77% for the years ended December 31, 2008, 2007 and 2006, respectively. Set forth below is our reserve replacement ratio for the periods indicated.

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(1)

In 2008, our reserve replacement ratio is negative due to the fact that our negative reserve revisions, resulting from both decreased prices and performance, exceeded our reserve additions. This is partially due to the fact that we had decreased capital re-investment as a result of our ongoing strategic alternatives process.

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Oil and Natural Gas Volumes, Prices and Operating Expense

        The following table sets forth certain information regarding production volumes, average sales prices and average operating expenses associated with our sale of oil and natural gas for the periods indicated.

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(1)

Includes direct lifting costs (labor, repairs and maintenance, materials and supplies), expensed workover costs, the administrative costs of field production personnel, and insurance costs. Transportation costs are netted from our revenues.

Exploration, Development and Acquisition Capital Expenditures

        The following table sets forth certain information regarding the total costs incurred in connection with exploration, development and acquisition activities.

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(1)

Asset retirement costs associated with the plugging and abandonment liability related to SFAS No. 143, Accounting for Asset Retirement Obligations , (see Note 7 to our consolidated financial statements) are included in this line.

        Net costs incurred excludes sales of proved oil and natural gas properties, which 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.

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Drilling Activity

        The following table sets forth our drilling activity for the periods indicated. In the table, "Gross" refers to the total wells in which we have a working interest or back-in working interest after payout and "Net" refers to gross wells multiplied by our working interest therein.

Productive Wells

        The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2008. In the table, "Gross" refers to the total wells in which we have a working interest or back-in working interest after payout and "Net" refers to gross wells multiplied by our working interest therein.

Acreage Data

        The following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31, 2008. Developed acres refer to acreage within producing units and undeveloped acres refer to acreage that has not been placed in producing units. In the table, "Gross"

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refers to the total acres in which we have an interest and "Net" refers to gross acres multiplied by our interest therein.

        Leases covering approximately 33,344 gross (12,904 net), 47,359 gross (31,216 net) and 16,131 gross (12,556 net) undeveloped acres are scheduled to expire in 2009, 2010 and 2011, respectively. In general, our leases will continue past their primary terms if oil and natural gas production in commercial quantities is being produced from a well on such lease or other drilling or reworking operations are being continuously prosecuted.

        The table above does not include 14,513 gross (9,977 net) undeveloped acres in Texas for which we have the option to acquire leases based upon a commitment of continuous drilling. We estimate that these options to acquire leased acreage will expire in 2009 and 2010, based on our current well and 3-D seismic acquisition schedule and our severely limited drilling program.

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Core Areas of Operation

        As of December 31, 2008, 83% of our proved reserves were in Texas, 6% in New Mexico, 6% in Mississippi, and 5% in Arkansas, south Louisiana, Michigan, and Alabama. In south Texas, our exploration and production activities are concentrated in three primary plays: Vicksburg, Queen City and Deep Frio trends. Our principal properties are located in the following areas of the United States:

        The table below sets forth the gross and net number of our gas, oil and service wells in each of our core areas of operation as of December 31, 2008. Net wells are calculated based on our working or net revenue interest in each of the properties we own.

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(1)

Service wells are wells drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

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        We conduct our operations primarily along the onshore United States Gulf Coast, with our primary emphasis in south Texas, southeast New Mexico, Mississippi, Arkansas and Louisiana. Our resources and assets are managed and our results reported as one operating segment. The following table sets out a brief comparative summary of certain key 2008 data for each area.

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Less than 1%

        Due to the ongoing financial and strategic alternatives process and our liquidity issues resulting from the Deficiency under our Revolving Facility and the related Amended Consent, our planned activities in all of our areas of operation will be severely limited in 2009.

South & Southeast Texas

        As of December 31, 2008, we owned an interest in 110,297 gross (47,264 net) acres in Texas. Our areas of focus in this region are predominantly in the Vicksburg, Queen City and Deep Frio producing trends. As of December 31, 2008, we operated approximately 248 gross wells, which along with our 162 gross non-operated wells, accounted for approximately 86% of our total net production in 2008. We drilled 16 gross wells during 2008 in Texas, of which 14 gross wells were apparent successes and all of which were in the Vicksburg project area. The majority of our 2008 asset divestitures were properties located in Texas.

Southeast New Mexico

        As of December 31, 2008, we owned an interest in 99,837 gross (21,001 net) acres in southeast New Mexico that we earned through a drilling obligation we fulfilled during 2004 and 2005 and through subsequent purchases. The primary objectives in this area are shallow oil in the Yeso, San Andres, Queen and Grayburg formations, and natural gas in the Atoka and Morrow formations. Additional objectives include the Strawn, Cisco, Wolfcamp and Devonian formations. In 2008, we participated in the drilling of 10 gross (2.3 net) wells, of which all were apparently successful. As of December 31, 2008, we operated 34 gross wells in this area. Production from wells in the southeast New Mexico area represented approximately 8% of our total net production in 2008.

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Mississippi Interior Salt Basin

        As of December 31, 2008, we owned an interest in 19,822 gross (10,848 net) acres in the Mississippi Interior Salt Basin area and 26,273 gross (21,448 net) undeveloped acres in the Floyd Shale play. We acquired reserves and production in the Mississippi Interior Salt Basin in south central Mississippi as part of the 2003 merger with Miller Exploration Company ("Miller"). The primary producing horizons in the Mississippi Interior Salt Basin around the Miller properties include the Hosston, Sligo, Rodessa and James Lime sections. As of December 31, 2008, we operated 10 gross wells in this area. Production from wells in the Mississippi Interior Salt Basin accounted for approximately 4% of our total net production in 2008. We did not drill any wells in Mississippi in 2008. A portion of our 2008 asset divestitures included our Tallahalla Creek field in Mississippi.

South Louisiana

        As of December 31, 2008, we owned an interest in 1,583 gross (463 net) acres in south Louisiana primarily located in Acadia and Lafayette Parishes. As of December 31, 2008, we had an interest in six gross wells, none of which we operate. Production from wells in south Louisiana represented approximately 1% of our total net production in 2008. We did not drill any wells in south Louisiana in 2008.

Arkansas

        As of December 31, 2008, we owned an interest in 5,661 gross (4,801 net) undeveloped acres in the Fayetteville Shale play in south central Arkansas. In 2008, we drilled one gross (0.04 net) apparently successful well. Five wells in Arkansas had operations temporarily suspended at year-end 2007 because fracture stimulation during the completion of our initial wells caused communication with an underlying water bearing zone. We are currently seeking approval to convert one of our existing shut-in wells to a water disposal well. If successful, we plan to return three currently shut-in wells to production and re-inject the produced water from these wells into the water disposal system. Much of the planned 2008 wells have been deferred. Production from wells in the Arkansas area represented less than 1% of our total net production in 2008.

Michigan

        As of December 31, 2008, we owned an interest in 658 gross (658 net) acres in Michigan. We acquired acreage and one producing well in south central Michigan as part of the 2003 merger with Miller. We operate this well which produces from the Trenton/Black River formation at approximately 3,000 feet and this well accounted for approximately 1% of our total net production in 2008. We did not drill any wells in Michigan in 2008.

Title to Properties

        We believe we have satisfactory title to all of our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect the value of such properties. As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). Detailed investigations, including a title opinion rendered by a licensed attorney, are made before commencement of drilling operations.

        We have granted mortgage liens on substantially all of our oil and natural gas properties in favor of Union Bank of California, as agent, to secure our Revolving Facility. These mortgages and the Revolving Facility contain substantial restrictions and operating covenants that are customarily found in

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loan agreements of this type. See ITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS —LIQUIDITY AND CAPITAL RESOURCES— REVOLVING FACILITY" and Note 11 to our consolidated financial statements.

Marketing

        Our production is marketed to third parties consistent with industry practices. We market our own production where feasible and we also engage third-party marketing agents. We use third-party agents to market our residue gas in interstate pipelines. Typically, oil is sold at the well-head at either (1) NYMEX average price basis, (2) field-posted prices or (3) Platt's plus posting, less transportation costs. Typically, natural gas is sold under contract at a negotiated monthly price based upon factors normally considered in the industry, such as processing, conditioning or treating to make gas marketable, distance from the well to the transportation pipeline, well pressure, estimated reserves, quality of natural gas and prevailing supply/demand conditions.

        Our marketing objective is to receive the highest possible wellhead price for our product. We are aided by the presence of multiple outlets near our production on the Gulf Coast. We take an active role in determining the available pipeline alternatives for each property based upon historical pricing, capacity, pressure, market relationships, seasonal variances and long-term viability.

        There are a variety of factors which affect the market for oil and natural gas, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulations on oil and natural gas production and sales. We have not experienced any significant difficulties in marketing our oil and natural gas. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual customers. Where feasible, we use a combination of market-sensitive pricing and forward-fixed pricing. Forward pricing is utilized to take advantage of anomalies in the futures market.

Delivery Commitments

        During 2007, we 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 our desire to be able to deliver natural gas as soon as our wells were completed. At the time of signing the contract, we had completed and tested two productive wells in the Moorefield shale. The Rose Bud system was installed, operational and ready to deliver our 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. We have delivered approximately $63,800 of this commitment through December 31, 2008. 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. 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. See Note 11 to our consolidated financial statements and ITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS— LIQUIDITY AND CAPITAL RESOURCES".

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        During 2008, we executed a gas gathering and compression services agreement with Integrys Energy Services ("Integrys") related to the construction and installation of a pipeline connecting our Slick State properties to our 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 our production in September 2008. The contract minimum commitment to Integrys is approximately 11.2 Bcf over a three year period for the pipeline interconnect. The amount of total commitment is $550,000 plus 8% interest per annum, for a total liability of approximately $0.6 million. We have delivered approximately $71,400 of this commitment through December 31, 2008. We have not recorded a liability for this commitment as we expect to meet the minimum physical delivery based on estimated anticipated production.

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

Derivatives

        Due to the volatility of oil and natural gas prices, from time to time, we may enter 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 to commodity price fluctuations. While the use of these arrangements may limit our ability to benefit from increases in the prices of oil and natural gas, it is also intended to reduce our potential exposure to adverse price movements. 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 were, at the time of their execution, intended to be used for trading or speculative purposes, but a portion of these instruments was subsequently deemed as such because of the decrease in our 2008 production. The use of derivative instruments involves some credit risk, but generally we place our derivative transactions 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. On a quarterly basis, our management sets all of our price-risk management policies, including volumes, types of instruments and counterparties. Our Board of Directors monitors the Company's price-risk management policies and trades on a monthly basis. We account for these transactions as derivative activities and, accordingly, certain gains and losses are included in total revenue during the period the transactions occur. See Note 9 to our consolidated financial statements and ITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS— CRITICAL ACCOUNTING POLICIES AND ESTIMATES—DERIVATIVES AND HEDGING ACTIVITIES".

        All of these price-risk management transactions are considered derivative instruments and accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended). These derivative instruments are intended to hedge our price risk and may be considered hedges for economic purposes. There are two types of accounting treatments for derivatives, (i) mark-to-market accounting and (ii) cash flow hedge accounting. For a discussion of these accounting treatments, see Note 9 to our consolidated financial statements. We evaluate the terms of new contracts when entered into to determine whether cash flow hedge accounting treatment or mark-to-market accounting treatment will be applied. Prior to 2006, we used mark-to-market accounting treatment for our crude oil derivative contracts and cash flow hedge accounting treatment for our natural gas derivative contracts. Beginning in the first quarter of 2006, we applied mark-to-market accounting treatment to all outstanding derivative contracts. Currently all derivatives, other than those that meet the normal purchases and sales exception, 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. Cash flows from resulting derivative settlements are included in operating activities and investing activities on the statement of cash flows.

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        The table below shows derivative gains and losses included within total revenue for the years presented.

        The table below summarizes our outstanding derivative contracts reflected on the balance sheet at December 31, 2008 and 2007.

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(1)

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

(2)

Our crude oil contracts were 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 these contracts and the change in fair value is reflected in total revenue.

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Sales to Major Customers

        We sold natural gas and crude oil production representing 10% or more of our total revenues to the following major customers for the years presented.

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*

Zero or less than 1%.

(1)

Integrys Energy Services is an agent that sells our production to other purchasers on our behalf.

NOTE: Amounts disclosed are approximations and those that are less than 10% are presented for information and comparison purposes only. These percentages do not consider the effects of financial derivative instruments.

        In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all our customers are concentrated in the oil and gas industry, and our revenue can be materially affected by current economic conditions and the price of certain commodities such as natural gas and crude oil, the cost of which is passed through to the customer. However, based on the current demand for natural gas and crude oil and the fact that alternate purchasers are readily available, we believe that the loss of any of our major purchasers would not have a long-term material adverse effect on our operations.

Competition

        We compete with other oil and natural gas companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. We will have limited ability to explore for oil and natural gas reserves and to acquire additional properties in the future. Any such exploration or other activities will be dependent on the success of our financial and strategic alternatives process. Our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment will also affect our exploration and other activities. See ITEM 1A. "RISK FACTORS —We face strong competition from larger oil and natural gas companies," and "—Our January 2009 borrowing base redetermination resulted in a $114 million borrowing base deficiency under our Revolving Facility and we may not be able to satisfy the terms and conditions of our Amended Consent relating thereto or to otherwise repay our borrowing base deficiency or satisfy our other liabilities," and "—Our ability to continue as a going concern is dependent upon a financial restructuring and/or the consummation of one or more strategic alternatives."

Industry Regulations

        The availability of a ready market for oil and natural gas production depends upon numerous factors beyond our control. These factors include regulation of oil and natural gas production, federal and state regulations governing environmental quality and pollution control, state limits on allowable rates of production by well or proration unit, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of

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competitive fuels. For example, a productive natural gas well may be "shut-in" because of an oversupply of natural gas or lack of an available natural gas pipeline or market in the areas in which we may conduct operations. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The following discussion summarizes the regulation of the United States oil and natural gas industry. We believe that we are in substantial compliance with the various statutes, rules, regulations and governmental orders to which our operations may be subject, although there can be no assurance that this is or will remain the case. Moreover, such statutes, rules, regulations and government orders may be changed or reinterpreted from time to time in response to economic or political conditions, and there can be no assurance that such changes or reinterpretations will not materially adversely affect our results of operations and financial condition. The following discussion is not intended to constitute a complete discussion of the various statutes, rules, regulations and governmental orders to which our operations may be subject.

        Regulation of Oil and Natural Gas Exploration and Production.     Our operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells that may be drilled in and the unitization or pooling of oil and natural gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore more difficult to develop a project, if the operator owns less than 100% of the leasehold. In addition, state conservation laws which establish maximum rates of production from oil and natural gas wells generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. The regulatory burden on the oil and natural gas industry increases our costs of doing business and, consequently, affects our profitability. Inasmuch as such laws and regulations are frequently expanded, amended and interpreted, we are unable to predict the future cost or impact of complying with such regulations.

        Regulation of Sales and Transportation of Natural Gas.     Federal legislation and regulatory controls have historically affected the price of natural gas produced by us, and the manner in which such production is transported and marketed. Under the Natural Gas Act of 1938 (the "NGA"), the Federal Energy Regulatory Commission (the "FERC") regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act") deregulated natural gas prices for all "first sales" of natural gas, including all sales by us of our own production. As a result, all of our domestically produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. However, the Decontrol Act did not affect the FERC's jurisdiction over natural gas transportation. Under the provisions of the Energy Policy Act of 2005 (the "2005 Act"), the NGA has been amended to prohibit any form of market manipulation in connection with the purchase or sale of natural gas, and the FERC has issued new regulations to implement this prohibition. In addition, under the 2005 Act the FERC issued new regulations that are intended to increase natural gas pricing transparency through, among other things, expanded dissemination of information about the availability

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and prices of gas sold. The 2005 Act also has significantly increased the penalties for violations of the NGA.

        Our natural gas sales are affected by intrastate and interstate gas transportation regulation. Following the Congressional passage of the Natural Gas Policy Act of 1978, the FERC adopted a series of regulatory changes that have significantly altered the transportation and marketing of natural gas. Beginning with the adoption of Order No. 436, issued in October 1985, the FERC has implemented a series of major restructuring orders that have required pipelines, among other things, to perform "open access" transportation of gas for others, "unbundle" their sales and transportation functions, and allow shippers to release their unneeded capacity temporarily and permanently to other shippers. As a result of these changes, sellers and buyers of gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. It remains to be seen, however, what effect the FERC's other activities will have on access to markets, the fostering of competition and the cost of doing business. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. We do not believe that we will be affected by any such new or different regulations materially differently than any other seller of natural gas with which we compete.

        In the past, Congress has been very active in the area of gas regulation. However, as discussed above, the more recent trend has been in favor of deregulation, or "lighter handed" regulation, and the promotion of competition in the gas industry. There regularly are other legislative proposals pending in the Federal and state legislatures that, if enacted, would significantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Similarly, and despite the trend toward federal deregulation of the natural gas industry, we cannot predict whether or to what extent that trend will continue, or what the ultimate effect will be on our sales of gas. Again, we do not believe that we will be affected by any such new legislative proposals materially differently than any other seller of natural gas with which we compete.

        We own certain natural gas pipelines that we believe meet the standards the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA. These gathering facilities are regulated for safety compliance by the U.S. Department of Transportation ("DOT") and/or by state regulatory agencies.

        The intrastate pipeline system in Texas is regulated for safety compliance by the DOT and the Texas Railroad Commission. In 2002, the United States Congress enacted the Pipeline Safety Improvement Act of 2002 (the "2002 Act"), which contains a number of provisions intended to increase pipeline operating safety. The DOT's final regulations implementing the 2002 Act became effective in February 2004. Among other provisions, the regulations require that pipeline operators implement a pipeline integrity management program that must at a minimum include an inspection of gas transmission pipeline and non-rural gathering facilities within the next ten years, and at least every seven years thereafter. In December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, which reauthorizes the programs adopted under the 2002 Act, proposes enhancements for state programs to reduce excavation damage to pipelines, establishes increased federal enforcement of one-call excavation programs, and establishes a new program for review of pipeline security plans and critical facility inspections. In addition, beginning in October 2005, the DOT's Pipeline and Hazardous Materials Safety Administration commenced a rulemaking proceeding to develop rules that would better distinguish onshore gathering lines from production facilities and transmission lines, and to develop safety requirements better tailored to gathering line risks. On March 15, 2006, the DOT revised its regulations to define more clearly the categories of gathering facilities subject to DOT regulation, established new safety rules for certain gathering lines in

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rural areas, revised the current regulations applicable to safety and inspection of gathering lines in nonrural areas, and adopted new compliance deadlines. In January 2007, we acquired several lines that are subject to annual inspection and maintenance and we have DOT permits on 10 lines with the Texas Railroad Commission. In addition to safety regulation, state regulation of gathering facilities generally includes various environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Natural gas gathering may receive greater regulatory rate and service scrutiny at the state level in the post-restructuring environment.

        Oil Price Controls and Transportation Rates.     Sales of crude oil, condensate and gas liquids by us are not currently regulated and are made at market prices. The price we receive from the sale of these products may be affected by the cost of transporting the products to market. Much of the transportation is through interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. The FERC's regulation of oil transportation rates may tend to increase the cost of transporting oil and natural gas liquids by interstate pipelines, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In March 2006, to implement the second of the required five-yearly redeterminations, the FERC established an upward adjustment in the index to track oil pipeline cost changes. The FERC determined that the Producer Price Index for Finished Goods plus 1.3 percent (PPI plus 1.3 percent) should be the oil pricing index for the five-year period beginning July 1, 2006. We are not able at this time to predict the effects of these regulations or FERC proceedings, if any, on the transportation costs associated with oil production from our oil producing operations.

        Environmental Regulations.     Our operations are subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands within wilderness, wetlands and other protected areas, require remedial measures to eliminate or mitigate pollution from current and former operations and properties we currently own or operate or previously owned or operated, such as pit closure, plugging abandoned wells and releases of hydrocarbons, and impose substantial liabilities for pollution resulting from production and drilling operations. A trend of more expansive and stricter environmental legislation and regulations applied to the oil and natural gas industry has occurred and could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected.

        We generate wastes that may be subject to the federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Furthermore, certain wastes generated by our oil and natural gas operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements.

        We currently own or lease numerous properties that for many years have been used for the exploration and production of oil and natural gas. Although we believe that we have used good operating and waste disposal practices in effect at the time, these practices have changed over time and

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prior owners and operators of these properties may not have used similar practices, and hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws as well as state laws governing the management of oil and natural gas wastes. Under such laws, liability may be imposed, without regard to fault or the legality of the original conduct, on certain classes of persons. These persons include the current owner or operator of the disposal site or sites where the release occurred, past owners or operators that owned or operated the site at the time of the release, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are liable under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination or to pay for the foregoing.

        Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention, control, countermeasure ("SPCC") and response plans relating to the possible discharge of oil into surface waters. SPCC plans at our producing properties were developed and implemented in 1999. The Oil Pollution Act of 1990 ("OPA") contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. Noncompliance with OPA may result in varying administrative, civil and criminal penalties and liabilities. Our operations are also subject to the federal Clean Water Act ("CWA") and analogous state laws. Like OPA, the CWA and analogous state laws relating to the control of water pollution provide varying civil and criminal penalties and liabilities for releases of petroleum or its derivatives and other substances into surface waters or into the ground.

        Our operations may be subject to the Clean Air Act ("CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that have resulted in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states developed and continue to develop regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with regulatory requirements and maintaining or obtaining permits and approvals addressing other air emission-related issues. However, we do not believe our operations will be materially adversely affected by any such requirements.

        In response to studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to warming of the Earth's atmosphere, the U.S. Congress is actively considering climate change-related legislation to restrict greenhouse gas emissions, including carbon dioxide and methane, both of which are emitted in our operations. A number of bills being considered propose a "cap and trade" scheme of regulation of greenhouse gas emissions—a ban on emissions above a defined reducing annual cap with covered parties authorized to emit greenhouse emissions in a quantity decreasing through time and also through the acquisition of emission allowances that may be traded or acquired on the open market. In addition, numerous states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.

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        We could be required to purchase and surrender allowances. Although we do not expect to be impacted to a greater degree than other similarly situated producers of oil and natural gas, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the oil and natural gas we produce.

        Also, as a result of the U.S. Supreme Court's decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate carbon dioxide and other greenhouse gas emissions from mobile sources such as cars and trucks, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court's holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal CAA's definition of "air pollutant" may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New federal or state restrictions on emissions of greenhouse gases that may be imposed in areas of the United States in which we conduct business could also adversely affect our cost of doing business and demand for the oil and natural gas we produce.

        We also are subject to a variety of federal, state and local permitting and registration requirements relating to protection of the environment. Management believes that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse effect on us.

Operating Hazards and Insurance

        The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosion, blow-out, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures and discharges of toxic gases, the occurrence of any of which could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations.

        In accordance with customary industry practice, we maintain insurance against some, but not all, of the risks described above. Our insurance does not cover business interruption or protect against loss of revenue. There can be no assurance that any insurance obtained by us will be adequate to cover any losses or liabilities. We cannot predict the continued availability of insurance or the availability of insurance at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and operations.

ITEM 1A.    RISK FACTORS

Our January 2009 borrowing base redetermination resulted in a $114 million borrowing base deficiency under our Revolving Facility and we may not be able to satisfy the terms and conditions of our Amended Consent relating thereto or to otherwise repay our borrowing base deficiency or satisfy our other liabilities.

        In January 2009, we announced the Deficiency due to a redetermination of our borrowing base to $125 million. Pursuant to the terms of the Revolving Facility, we elected to prepay the Deficiency in six equal monthly installments, with the first $19 million installment being due on February 9, 2009. On February 9, 2009, we entered into 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 $19 million installment payments to be due on August 10, 2009. Under the February Consent, we agreed to prepay $5.0 million of our 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 the prepayments to be applied on

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a pro rata basis to reduce the remaining six $19 million deficiency payments. On March 10, 2009, we entered into 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 the Amended Consent which provides, among other things, (1) that we will 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 will be an event of default (i) if we fail 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 are in default under or our hedging arrangements have been terminated or cease to be effective without the prior written consent of our Lenders, (3) that our advances under the Revolving Facility will 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% as of March 16, 2009), (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 eliminates the six $19 million deficiency payments which were contemplated by the February Consent and the March Consent. To comply with the terms of the Amended Consent, we anticipate that we will need to (i) sell select individual assets prior to May 31, 2009 to enable us to make the $25 million payment which is due on May 31, 2009, and/or (ii) negotiate a commitment letter with a new lender or group of lenders prior to May 15, 2009 in an amount sufficient to repay all of our obligations under the Revolving Facility on or before June 30, 2009, and/or (iii) have negotiated the sale, merger or other business combination involving us which results in the repayment of all of our obligations under the Revolving Facility prior to May 15, 2009 and to have closed such transaction on or before June 30, 2009. The Amended Consent limits the making of capital expenditures and we anticipate a severe curtailment of our drilling plans and other capital expenditures in 2009.

        If we breach any of the provisions of the Amended Consent or the Revolving Facility, our Lenders will be entitled to declare an event of default, at which point the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, would become immediately due and payable. In any event, the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, will be payable on June 30, 2009 unless earlier paid or a further extension with respect to payment is negotiated with our Lenders. Our Lenders may take action to enforce their rights with respect to the outstanding obligations under the Revolving Facility. Because substantially all of our assets are pledged as collateral under the Revolving Facility, if our Lenders declare an event of default, they would be entitled to foreclose on and take possession of our assets. In such an event, we may be forced to liquidate or to otherwise seek protection under Chapter 11 of the U.S. Bankruptcy Code. These matters, as well as the other risk factors related to our liquidity and financial position raise substantial doubt as to our ability to continue as a going concern. See ITEM 7. "MANAGEMENT'S DISCUSSION

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AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS —LIQUIDITY AND CAPITAL RESOURCES— REVOLVING FACILITY." With respect to our compliance with the Amended Consent, there can be no assurance that we will be able to further negotiate the terms of the Amended Consent or negotiate a further restructuring of the related indebtedness or that we will be able to make any required payments when they become due. Moreover, there can be no assurance that we will be successful in our efforts to comply with the terms of the Amended Consent, including our ongoing efforts to evaluate and assess our various financial and strategic alternatives (which may include the sale of some or all of our assets, a merger or other business combination involving the Company, or the restructuring or recapitalization of the Company). If such efforts are not successful, we may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

Our ability to continue as a going concern is dependent upon a financial restructuring and/or the consummation of one or more strategic alternatives.

        In addition to the Deficiency under our Revolving Facility, the capital expenditures required to maintain and/or grow production and reserves are substantial. Our stock price has significantly declined over the past year which makes it more difficult to obtain equity financing on acceptable terms to address our liquidity issues. In addition, we are reporting negative working capital at December 31, 2008 and a third consecutive year of net losses for the year ended December 31, 2008, which is largely the result of impairments of our oil and natural gas properties. We have also recently substantially curtailed our operations due to reduced liquidity and a lack of external financing alternatives. Therefore, there is substantial doubt as to our ability to continue as a going concern for a period longer than the current fiscal year. Our independent auditors have included an explanatory paragraph in their report on our consolidated financial statements that raises substantial doubt about our ability to continue as a going concern See ITEM 8. "FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA —Report of the Independent Registered Accounting Firm." Our ability to continue as a going concern is dependent upon the success of our financial and strategic alternatives process, which may include the sale of some or all of our assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company. Until the possible completion of the financial and strategic alternatives process, our future remains uncertain and there can be no assurance that our efforts in this regard will be successful.

        Our business requires substantial working capital to fund ongoing exploration, development and acquisition programs, and our financial condition is dependent, at least in part, upon our ability to access capital at rates and on terms we determine to be attractive which has recently become exceptionally difficult. In addition, the significant declines in the prices of our stock have made it even more difficult for us to effectively raise capital by accessing the equity markets. In order to generate incremental cash flows, we need to drill productive oil or natural gas wells. Because we do not currently have sufficient access to capital either from equity markets or our Revolving Facility, we will need to raise the funds required to drill new wells from third parties willing to pay our share of the costs of drilling and completing the wells. We may not be successful in raising such capital and we currently do not have any availability under our Revolving Facility. In addition, we are limited in our ability to expend capital under the terms of the Amended Consent. Any future wells which we may drill may not be productive of oil or natural gas. Our inability to generate cash flows may force us to further curtail or cease certain operations. Further sales of producing properties may further reduce our ability to borrow and to benefit from any future cash flow attributable to those properties. If our operations do not provide the liquidity required to operate our business, our drilling and other activities may be further curtailed, our cash flow and financial condition would be further materially adversely affected and we would become highly vulnerable to further adverse general economic consequences and industry conditions. In such event, we may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

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        As discussed above, in January 2009 the Lenders to our Revolving Facility completed their borrowing base redetermination and reduced our borrowing base to $125 million, resulting in a borrowing base deficiency of $114 million and we recently entered into the Amended Consent relating to the repayment of our obligations under the Revolving Facility. As further discussed above, we will need to take certain actions to comply with the terms of the Amended Consent. Absent our success with respect to such actions, we will be unable to comply with the terms of the Amended Consent and make the payments due thereunder.

        There can be no assurance that we will be able to further negotiate the terms of the Amended Consent or a further restructuring of the related indebtedness or that the Company will be able to make any required payments when they become due. We have retained an investment banking firm to assist further in the evaluation of our strategic and financial alternatives. There can be no assurance that the Company's ongoing efforts to evaluate and assess its various financial and strategic alternatives (which may include the sale of some or all of our assets, a merger or other business combination involving the Company, or the restructuring or recapitalization of the Company) will be successful. If such efforts are not successful, the Company may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

        Even if we are able to address our immediate liquidity issues, our history of losses may impair our ability to obtain financing for drilling and other business activities on favorable terms or at all. It may also impair our ability to attract investors if we attempt to raise additional capital to grow our business, or for other business purposes, by selling additional debt or equity securities in a private or public offering. If we are unable to obtain additional financing, we may be unable to maintain and develop our properties and if such efforts are not successful, the Company may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

Our Revolving Facility has substantial operating restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect operations.

        Over the past few years, increases in commodity prices and proved reserve amounts resulted in increased estimated discounted future net revenue which allowed us to increase our available borrowing amounts. Recently commodity prices have rapidly declined and therefore reserve estimates have been revised, which has impacted our borrowing base. More specifically and as discussed above, our borrowing base has been reduced to $125 million resulting in a borrowing base deficiency of $114 million. Our obligations under the Revolving Facility are secured by a pledge of substantially all of our assets. The Revolving Facility has covenants that limit additional borrowings, sales of assets and the distributions of cash or properties and that prohibit the payment of dividends on our common stock and the incurrence of liens. For the foreseeable future, we will not have borrowing capacity under our Revolving Facility. We intend to continue to monitor closely our cash position and are limiting our capital and other expenditures. The restrictions of our Revolving Facility and the difficulty in obtaining additional debt financing will have adverse consequences on our operations and financial results, including our ability to obtain financing for working capital, capital expenditures, our drilling program, purchases of new technology or other purposes. In addition, such financing (if it is able to be obtained), may be on terms unfavorable to us and we may be required to use a substantial portion of our cash flow to make debt service payments, which would further reduce the funds that would otherwise be available for operations and future business opportunities. Further, a decrease in our operating cash flow or an increase in our expenses will make it even more difficult for us to meet debt service requirements and require us to further modify operations, and thus we would become even more vulnerable to continued downturns in our business or the economy generally.

        Our ability to obtain and service indebtedness will depend on our ability to restructure our debt or pursue strategic alternatives as well as our future performance, including our ability to manage cash flow and working capital, which are in turn subject to a variety of factors beyond our control. Our

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business may not generate cash flow at or above anticipated levels or we may not be able to borrow funds in amounts sufficient to enable us to service indebtedness, make anticipated capital expenditures or finance our drilling program. In this regard, we do not expect that our current cash flow will be in an amount sufficient to enable us to service our existing indebtedness or to make capital expenditures or finance our drilling program beyond that currently contemplated by our reduced capital budget. If we are unable to generate sufficient cash flow from operations or to borrow sufficient funds in the future to service our debt, we may be required to further curtail our drilling program, sell assets, reduce capital expenditures, refinance all or a portion of our existing debt or obtain additional financing. We may not be able to refinance our debt or obtain additional financing, particularly in view of our financial and strategic alternatives process, current industry conditions, the restrictions on our ability to incur debt under our existing debt arrangements, and the fact that substantially all of our assets are currently pledged to secure obligations under our Revolving Facility. See ITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS— LIQUIDITY AND CAPITAL RESOURCES" and "—REVOLVING FACILITY." If such efforts are not successful, the Company may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

We need to replace our reserves at a faster rate than companies whose reserves have longer production periods. Our failure to replace our reserves will result in decreasing reserves and production over time.

        Unless we conduct successful exploration and development activities or acquire properties containing proven reserves, our estimated proved reserves will decline as reserves are depleted. Producing oil and natural gas reserves are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. High production rates generally result in recovery of a relatively higher percentage of reserves from properties during the initial few years of production. A significant portion of our current operations are conducted in onshore Texas. Production from reserves in onshore Texas generally declines more rapidly than reserves from reservoirs in other producing regions. As a result, our need to replace reserves from new investments is relatively greater than those of producers who produce their reserves over a longer time period, such as those producers whose reserves are located in areas where the rate of reserve production is lower. If we are not able to find, develop or acquire additional reserves to replace our current and future production, our production rates will decline even if we drill the undeveloped locations that were included in our estimated proved reserves. Our future oil and natural gas reserves and production, and therefore our cash flow and income, are dependent on our success in economically finding or acquiring new reserves and efficiently developing our existing reserves. Our severely limited drilling program will restrict our ability to add to our reserve base for the foreseeable future.

Our common stock could be delisted from The NASDAQ Global Select Market, which could negatively impact the price of our common stock and our ability to access the capital markets. If we are delisted by The NASDAQ Global Select Market before we are able to be listed on another national stock exchange or approved for quotation on an over-the-counter market in the United States, we may be required to repurchase our outstanding Convertible Preferred Stock at 100% of its liquidation preference, plus any accumulated and unpaid dividends. If this were to occur, there would be a material adverse effect on our business, financial condition and results of operations.

        Our common stock is currently listed on The NASDAQ Global Select Market. The listing standards of The NASDAQ Global Select Market provide, among other things, that a company may be delisted if the bid price of its stock drops below $1.00 for a period of 30 consecutive business days. In October 2008, The NASDAQ Stock Market suspended enforcement of the $1.00 minimum bid requirement and the minimum market capitalization requirements through January 16, 2009 due to the rapid deterioration of the capital markets. In December 2008, given the continued extraordinary market conditions, The NASDAQ Stock Market extended its suspension of the $1.00 minimum bid

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requirement and the minimum market capitalization requirements through April 19, 2009. If we fail to comply with the listing standards, our common stock listing may be moved to The NASDAQ Capital Market, which is a lower tier market, or our common stock may be delisted and traded on the over-the-counter bulletin board network. Moving our listing to The NASDAQ Capital Market or other markets could adversely affect the liquidity of our common stock and the delisting of our common stock would significantly affect the ability of investors to trade our securities and could significantly negatively affect the value of our common stock. In addition, the delisting of our common stock could further depress our stock price and materially adversely affect our ability to raise capital on terms acceptable to us, or at all. Delisting from NASDAQ could also have other negative results, including the potential loss of confidence by suppliers and employees, the loss of institutional investor interest and fewer business development opportunities. At this time, absent a further continued suspension of the $1.00 minimum bid requirement and the minimum market capitalization requirements, we do not believe that we would be able to meet The NASDAQ Global Select Market listing standards.

        If our shares are delisted from The NASDAQ Global Select Market and we are unable to list our common stock on another national securities exchange or an over-the-counter market in the United States prior to such delisting, the holders of all of our 5.75% Series A cumulative convertible perpetual preferred stock (the "Convertible Preferred Stock") have a "put" right to require us to repurchase our Convertible Preferred Stock at a price in cash equal to 100% of the liquidation preference, plus accumulated and unpaid dividends. We do not currently have the liquidity necessary to repurchase our Convertible Preferred Stock and our ability to issue common stock in connection such repurchase may be limited. In the event that this put right were exercised and we were unable to pay the repurchase price in either cash or common stock, we may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

The current financial crisis and recession has negatively impacted the prices for our oil and natural gas production, limited access to the credit and equity markets, increased the cost of capital, and may have other negative consequences that we cannot predict.

        Our operations are affected by local, national and worldwide economic conditions. The consequences of a recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might also result in a decline in energy consumption, which may adversely affect our revenue, liquidity and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital. The events discussed above, together with our liquidity level and our recent financial performance, increase the likelihood that we would become highly vulnerable to further adverse general economic consequences and industry conditions and that our cash flow and financial condition may be materially adversely affected as a result thereof. See "—Our Revolving Facility has substantial operating restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect operations."

        The continued credit crisis and related turmoil in the global financial system and economic recession in the U.S. create financial challenges if conditions do not improve. In response to these crises, our existing Deficiency and declining natural gas and oil prices, we have reduced and refocused our 2009 capital budget. Historically we have accessed the capital markets to provide us with additional capital in addition to our cash flow from operations, our Revolving Facility and cash on hand. Our ability to access the capital markets has been restricted as a result of this crisis and may continue to be restricted at a time when we would like, or need, to raise capital. If our cash flow from operations does not improve and our access to capital is restricted, we may be required to further reduce our operating and capital budget, which could have a further material adverse effect on our results and future operations. The financial crisis may also limit the number of participants or reduce the values we are able to realize in asset sales or other transactions we may engage in to raise capital, making these

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transactions more difficult to consummate. Additionally, the current economic situation has affected the demand for natural gas and oil and has resulted in lower prices for natural gas and oil, which will have a negative impact on our revenues. Lower prices could also adversely affect the collectability of our trade receivables and cause our hedging arrangements to be unsuccessful if our counterparties are unable to perform their obligations.

Our ongoing financial and strategic alternatives process, including any transaction that might result therefrom, may reduce productivity because of its impact on our management, current and prospective employees and customers, suppliers and business partners.

        Our management will be required to devote substantial time to activities related to the financial and strategic alternatives process and any transaction resulting therefrom, which time could otherwise be devoted to pursuing other beneficial business opportunities.

        In addition, our current and prospective employees may be uncertain about their future roles and relationships with us. This uncertainty may affect our productivity or adversely affect our ability to attract and retain key management and employees.

        Our customers and business partners may not be as willing to continue to do business with us on the same or similar terms because of the financial and strategic assessment process or any resulting transaction. Changes in these business relationships could materially and adversely affect our business and results of operations.

        In connection with the Deficiency, we retained an investment banking firm to further assist us in an evaluation of our strategic alternatives, including a capital restructuring for the Company, a merger or other business combination involving the Company or the sale of some or all of the Company's assets. There can be no assurance that the Company will be successful in pursuing any such alternative. Moreover, there can be no assurance that the Company's ongoing efforts to evaluate and assess its various financial and strategic alternatives (which may include the sale of some or all of the Company's assets, a merger or other business combination involving the Company, restructuring of the Company's debt or the issuance of additional equity or debt) will be successful. If such efforts are not successful, the Company may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

The loss of key personnel could adversely affect us.

        We depend to a large extent on the services of certain key management personnel, including our executive officers and other key employees, the loss of any of which could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any of our employees. Recently there has been a strong demand for professionals in the oil and natural gas industry including geologists, geophysicists, engineers and other professionals. We believe that our success is dependent upon our ability to continue to employ and retain skilled technical personnel; however, current market conditions for professionals as well as uncertainty relating to the outcome of the financial and strategic alternatives process and the termination of the proposed merger with Chaparral has resulted in the departure of employees. Although we believe that we have thus far obtained replacements adequate for our current needs, the cumulative effect of these employee departures with additional departures could materially adversely affect us. See ITEM 4. "SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS— EXECUTIVE OFFICERS OF THE REGISTRANT" and "—SIGNIFICANT EMPLOYEES."

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Oil and gas drilling is a speculative activity and involves numerous risks and substantial and uncertain costs which could adversely affect us.

        Any future growth and maintenance of our reserves will be materially dependent upon the success of our future drilling program which is currently being severely curtailed. Drilling for oil and gas involves numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including unexpected drilling conditions, pressure or irregularities in formations, unexpected communication with water-bearing zones, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rigs or crews and the delivery of equipment. Our future drilling activities may not be successful or may be significantly curtailed and, if unsuccessful or curtailed, such failure or curtailment will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate for activity within a particular geographic area may decline. We may ultimately not be able to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may not be able to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule can be difficult to predict and may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:

•

the results of exploration efforts and the acquisition, review and analysis of the seismic data;



•

the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;



•

the approval of the prospects by other participants after additional data has been compiled;



•

economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability of drilling rigs and crews;



•

our financial resources and results;



•

the availability of leases and permits on reasonable terms for the prospects; and



•

the terms of the Amended Consent and any other limitations placed on our capital expenditures by our lenders.

        These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive oil or natural gas. Our drilling operations have been severely curtailed as a result of our current liquidity issues and we expect to maintain a drilling program which is severely limited and which is not likely to result in effectively replacing the reserves that we produce. See ITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS —GENERAL OVERVIEW—INDUSTRY AND ECONOMIC FACTORS" and ITEMS 1 AND 2. "BUSINESS AND PROPERTIES— CORE AREAS OF OPERATION."

Oil and natural gas prices are highly volatile in general and low prices negatively affect our financial results and may further impact our borrowing base under our Revolving Facility resulting in additional borrowing base deficiencies.

        Our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas. Our reserves are predominantly natural gas, therefore changes in natural gas prices may have a particularly large impact on our financial results. Lower oil and natural gas

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prices also may reduce the amount of oil and natural gas that we can produce economically. Historically, the markets for oil and natural gas have been volatile, and such markets are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. These factors include the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions, the foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Declines in oil and natural gas prices may further impact our borrowing base under our Revolving Facility resulting in additional borrowing base deficiencies in excess of our current Deficiency and materially adversely affect our financial condition, liquidity, and ability to finance planned capital expenditures and operations. This borrowing base deficiency was largely the result of lower commodity prices and increased costs which impacted the reserve calculation used to redetermine our borrowing base along with our inability to replace and increase our reserves over the last year. See ITEM 7. " MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS —RISK MANAGEMENT ACTIVITIES—DERIVATIVES AND HEDGING" and ITEMS 1 AND 2. " BUSINESS AND PROPERTIES —OIL AND NATURAL GAS RESERVES" and "—MARKETING."

        We have in the past (most recently in the third and fourth quarters of 2008) and may in the future be required to write down the carrying value of our oil and natural gas properties. This may happen for several reasons, including a revision in reserve estimates and depression or unusual volatility in oil and natural gas prices. Whether we will be required to take such a charge will depend on the prices for oil and natural gas at the end of any quarter (or at the respective subsequent pricing date) and the effect of reserve additions or revisions and capital expenditures during such quarter. If a write down is required, it would result in a charge to earnings, but would not impact cash flow from operating activities.

We have hedged and may continue to hedge our production, which may result in our making cash payments, prevent us from receiving the benefit of increases in prices for oil and natural gas or expose us to risk of financial loss at times when production is less than expected.

        In order to reduce our exposure to short-term fluctuations in the price of oil and natural gas, we periodically enter into hedging arrangements. At the time we enter into our hedging arrangements, they 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. The use of hedging arrangements involves some credit risk, but generally we place our derivative transactions 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. Our hedging arrangements may also expose us to risk of financial loss in certain circumstances, including instances where production is less than expected, our customers fail to purchase contracted quantities of oil or natural gas or a sudden, unexpected event materially impacts oil or natural gas prices. In that regard, our changes in 2008 production and asset divestitures resulted in our derivative contracts covering approximately 115% and 190% of our 2008 natural gas and crude oil production, respectively. This overhedged position exposed us to greater risk of commodity price increases because we did not have the physical production cash inflows to offset the losses incurred on the portion of the contracts that were overhedged. See ITEM 7. " MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS— RISK MANAGEMENT ACTIVITIES—DERIVATIVES AND HEDGING" and ITEMS 1 AND 2. " BUSINESS AND PROPERTIES— DERIVATIVES."

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We depend on successful exploration, development and acquisitions to maintain reserves and revenue in the future.

        In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we acquire properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent upon our level of success in finding or acquiring additional reserves.

        If we fail to replace reserves though drilling or acquisitions, our level of production and cash flows will be adversely affected. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. We intend to dedicate the majority of our capital expenditures in the immediate future to further developing a limited selection of properties which will limit our ability to replace the reserves that we produce. Exploration activities involve numerous risks, including the risk that no commercially productive natural gas reservoirs will be discovered and/or recoverable. In addition, the future cost and timing of drilling, completing and tying-in wells are often uncertain. Our exploration and development operations may be curtailed, delayed or cancelled as a result of a variety of factors, including, inadequate capital resources, reductions in oil and natural gas prices and limitations in the market for oil and natural gas. In addition, we are dependent on finding partners for our exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we could be adversely affected.

        Our ability to maintain or increase our reserves will be constrained as we comply with the terms of the Amended Consent which will reduce our capital expenditures and drilling activities. To the extent that we are unable to obtain additional financing to fund our exploration and development activities, our reserves will further decline and our borrowing base under our Revolving Facility could be further adjusted downward.

We are subject to substantial operating risks that may adversely affect the results of our operations.

        The oil and natural gas business involves certain operating hazards such as well blowouts, mechanical failures, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pollution, releases of toxic gas and other environmental hazards and risks. We could suffer substantial losses as a result of any of these events. We are not fully insured against all risks incident to our business.

        We are not the operator of some of our wells. As a result, our operating risks for those wells and our ability to influence the operations for these wells are less subject to our control. Operators of these wells may act in ways that are not in our best interests. See ITEMS 1 AND 2. " BUSINESS AND PROPERTIES— OPERATING HAZARDS AND INSURANCE."

We cannot control the activities on properties we do not operate and are unable to ensure their proper operation and profitability.

        We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator's breach of the applicable agreements or an operator's failure to act in ways that are in our best interest could reduce our production and revenues. The success and timing of our drilling and development activities on

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properties operated by others therefore depend upon a number of factors outside of our control, including the operator's

•

timing and amount of capital expenditures;



•

expertise and financial resources;



•

inclusion of other participants in drilling wells; and



•

use of technology.

Our operations have significant capital requirements which, if not met, will hinder operations.

        We have experienced and expect to continue to experience substantial working capital needs due to our ongoing exploration, development and acquisition programs. Additional financing will be required in the future to fund our growth. We may not be able to obtain such additional financing, and financing under existing or new credit facilities may not be available in the future. In the event such capital resources are not available to us, our drilling and other activities may be further curtailed and we expect that our drilling and other activities will be significantly curtailed in 2009 as we comply with the terms of the Amended Consent and pursue strategic alternatives. See ITEM 7. " MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS— LIQUIDITY AND CAPITAL RESOURCES."

High demand for field services and equipment and the ability of suppliers to meet that demand may limit our ability to drill and produce our oil and natural gas properties.

        Due to industry demands, well service providers and related equipment and personnel may be in short supply as has occurred in recent years. This could cause escalating prices, delays in drilling and other exploration activities, the possibility of poor services coupled with potential damage to downhole reservoirs and personnel injuries. Such pressures will likely increase the actual cost of services, extend the time to secure such services and add costs for damages due to any accidents sustained from the over use of equipment and inexperienced personnel. In addition, even though commodity prices have rapidly declined in recent months, the costs of field services and equipment have not declined as rapidly.

Government regulation and liability for environmental matters may adversely affect our business and results of operations.

        Oil and natural gas operations are subject to various federal, state and local government regulations, which may be changed from time to time. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity in order to conserve supplies of oil and natural gas. There are federal, state and local laws and regulations relating to worker safety and protection of human health and the environment applicable to the development, production, handling, storage, transportation and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations. In addition, we may be liable for pollution and environmental damages we cause or related to facilities we currently or formerly owned or operated, even if caused by previous owners of property we purchase or lease. As a result, we may incur substantial liabilities to third parties or governmental entities. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The implementation of new, or the modification of existing, laws or regulations could have a material adverse effect on us. See ITEMS 1 AND 2. " BUSINESS AND PROPERTIES— INDUSTRY REGULATIONS."

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We face strong competition from larger oil and natural gas companies.

        The oil and gas industry is highly competitive. We encounter competition from oil and natural gas companies in all areas of our operations, including the acquisition of exploratory prospects and productive oil and natural gas properties. Our competitors range in size from the major integrated oil and natural gas companies to numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of these competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than ours. We may not be able to conduct our operations successfully, evaluate and select suitable properties, consummate transactions, and obtain technical, managerial and other professional personnel in this highly competitive environment. Moreover, our ability to explore for or acquire oil and natural gas reserves will be limited as a result of our ongoing financial and strategic alternatives process, the Amended Consent and the challenges and uncertainty facing our company currently. Additionally, larger competitors may be able to pay more for exploratory prospects, productive oil and natural gas properties and competent personnel and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such competitors may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. Such competitors may also be in a better position to secure oilfield services and equipment on a timely basis or on favorable terms. See ITEMS 1 AND 2. " BUSINESS AND PROPERTIES— COMPETITION."

The oil and natural gas reserve data included in or incorporated by reference in this document are estimates based on assumptions that may be inaccurate and existing economic and operating conditions that may differ from future economic and operating conditions.

        Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and is based upon assumptions that may vary considerably from actual results. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. The information regarding discounted future net cash flows included in this report should not be considered as the current market value of the estimated oil and natural gas reserves attributable to our properties. As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation. In addition, the 10% discount factor, which is required by the Financial Accounting Standards Board in Statement of Financial Accounting Standards ("SFAS") No. 69, Disclosures About Oil and Natural Gas Producing Activities , to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. See ITEMS 1 AND 2 . " BUSINESS AND PROPERTIES— OIL AND NATURAL GAS RESERVES."

We may not have enough insurance to cover all of the risks we face.

        In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We do not carry business interruption insurance and our insurance does not protect against loss of revenue. We cannot predict the continued availability of insurance and we may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully

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covered by insurance could have a material adverse effect on our financial condition and results of operations.

Our ability to utilize net operating loss carryforwards may be limited.

        At December 31, 2008, we had estimated net operating loss carryforwards ("NOLs") of $124.9 million, without consideration of valuation allowance for federal income tax purposes that expire beginning in 2012. We also had state NOL carryforwards at December 31, 2007 of $21.4 million, without consideration of valuation allowance, which will expire in varying amounts between 2009 and 2028. Due to recurring losses in recent years, utilization of the Company's NOL's may not be more likely than not, which would require the Company to establish a valuation allowance against the related deferred tax asset on the books. See Note 17 to our consolidated financial statements. Our ability to utilize federal and state NOL carryforwards in cases where the NOL was acquired in a reorganization may be subject to limitations under Section 382 of the Internal Revenue Code of 1986, as amended ("Section 382"), if we undergo a majority ownership change as defined by Section 382.

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

        At December 31, 2008, under Section 382 rules, approximately $80.5 million of our total federal NOL carryforward of $124.9 million was subject to a potential annual limitation of $12 million. Of that $80.5 million, $22 million was subject to further annual limitations. The $22 million amount represents the following two separate limitations which occurred prior to 2008: (1) $17.4 million acquired in a December 2003 merger, which is subject to an annual limitation of approximately $1 million per year and (2) $5.4 million acquired in a November 2005 acquisition, which is subject to an annual limitation of approximately $2 million per year.

Approximately 21% of our proved reserves were undeveloped as of December 31, 2008, and those reserves may not ultimately be developed.

        As of December 31, 2008, approximately 21% of our proved reserves were undeveloped. Proved undeveloped reserves, by their nature, are less certain than other categories of proved reserves. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations and involves greater risks. Our reserve data for the properties assumes that to develop our reserves we will make significant capital expenditures and conduct these operations successfully. Although we have prepared estimates of these natural gas and oil reserves and the costs associated with

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these reserves in accordance with industry standards and SEC requirements, the estimated costs may not be accurate, development may not occur as scheduled and actual results may not be as estimated. In addition, the current curtailment of our drilling program in response to our ongoing liquidity issues and our compliance with the Amended Consent will make it unlikely that we will be able to develop these reserves in the foreseeable future.

We do not intend to pay dividends on our common stock and our ability to pay dividends on our common stock is restricted.

        We have not historically paid a dividend on our common stock, cash or otherwise, and do not intend to in the foreseeable future. We are currently restricted from paying dividends on common stock by our existing Revolving Facility and, in some circumstances, by the terms of our Convertible Preferred Stock. Any future dividends also may be restricted by our then-existing debt agreements. See ITEM 7. " MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS— LIQUIDITY AND CAPITAL RESOURCES" and Notes 11 and 13 to our consolidated financial statements.

Our reliance on third parties for gathering and distributing could curtail future exploration and production activities.

        The marketability of our production depends upon the proximity of our reserves to, and the capacity of, third-party facilities and services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities. The unavailability or lack of capacity of such services and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. A shut-in or delay or discontinuance could adversely affect our financial condition. In addition, federal and state regulation of oil and natural gas production and transportation affect our ability to produce and market our oil and natural gas on a profitable basis.

Provisions of Delaware law and our charter and bylaws may delay or prevent transactions that would benefit stockholders.

        Our Certificate of Incorporation and Bylaws and the General Corporation Law of the State of Delaware contain provisions that may have the effect of delaying, deferring or preventing a change of control of the Company. These provisions, among other things, provide for a classified Board of Directors with staggered terms, restrict the ability of stockholders to take action by written consent, authorize the Board of Directors to set the terms of preferred stock, and restrict our ability to engage in transactions with stockholders with 15% or more of outstanding voting stock.

        Because of these provisions, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our Board of Directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent Board of Directors.

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ITEM 1B.    UNRESOLVED STAFF COMMENTS

        None.

CERTAIN DEFINITIONS

        The definitions set forth below shall apply to the indicated terms as used in this Annual Report. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

        After payout.     With respect to an oil or natural gas interest in a property, refers to the time period after which the costs to drill and equip a well have been recovered.

        Bbl.     One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

        Bbls/d.     Stock tank barrels per day.

        Bcf.     Billion cubic feet.

        Bcfe.     Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

        Before payout.     With respect to an oil and natural gas interest in a property, refers to the time period before which the costs to drill and equip a well have been recovered.

        British Thermal Unit or BTU.     The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

        Completion.     The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

        Condensate.     Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

        Developed acreage.     The number of acres which are allocated or assignable to producing wells or wells capable of production.

        Development costs.     Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. This definition of development costs has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the website at http://www.sec.gov/about/forms/forms-x.pdf .

        Development well.     A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

        Dry hole or well.     A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed the related oil and natural gas operating expenses and taxes.

        Exploration costs.     Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells. This definition of exploratory costs has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the website at http://www.sec.gov/about/forms/forms-x.pdf .

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        Exploratory well.     A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

        Farm-in or farm-out.     An agreement whereunder the owner of a working interest in an oil and natural gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty and/or reversionary interest in the lease. The interest received by an assignee is a "farm-in" while the interest transferred by the assignor is a "farm-out."

        Field.     An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

        Finding costs.     Costs associated with acquiring and developing proved oil and natural gas reserves which are capitalized by us pursuant to generally accepted accounting principles in the United States, including all costs involved in acquiring acreage, geological and geophysical work and the cost of drilling and completing wells, excluding those costs attributable to unproved property.

        Gross acres or gross wells.     The total acres or wells, as the case may be, in which a working interest is owned.

        Lease operating expenses.     The expenses of lifting oil or gas from a producing formation to the surface, and the transportation and marketing thereof, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, ad valorem taxes and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.

        MBbls.     One thousand barrels of crude oil or other liquid hydrocarbons.

        Mcf.     One thousand cubic feet.

        Mcf/d.     One thousand cubic feet per day.

        Mcfe.     One thousand cubic feet equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids, which approximates the relative energy content of crude oil, condensate and natural gas liquids as compared to natural gas. Prices have historically been higher or substantially higher for crude oil than natural gas on an energy equivalent basis although there have been periods in which they have been lower or substantially lower.

        MMBtu.     Million British Thermal Units.

        MMcf.     One million cubic feet.

        MMcf/d.     One million cubic feet per day.

        MMcfe.     One million cubic feet equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids, which approximates the relative energy content of crude oil, condensate and natural gas liquids as compared to natural gas.

        MMcfe/d.     One million cubic feet equivalent per day.

        Net acres or net wells.     The sum of the fractional working interests owned in gross acres or gross wells.

        NGL's.     Natural gas liquids measured in barrels.

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        NRI or net revenue interests.     The share of production after satisfaction of all royalty, overriding royalty, oil payments and other nonoperating interests.

        Normally pressured reservoirs.     Reservoirs with a formation-fluid pressure equivalent to 0.465 PSI per foot of depth from the surface. For example, if the formation pressure is 4,650 PSI at 10,000 feet, then the pressure is considered to be normal.

        Operator.     The individual or company responsible for the exploration and/or exploitation and/or production of an oil or gas well or lease.

        Over-pressured reservoirs.     Reservoirs with a formation fluid pressure greater than 0.465 PSI per foot of depth from the surface.

        Plant Products.     Liquids generated by a plant facility and include propane, iso-butane, normal butane, pentane and ethane.

        Plugging and abandonment.     Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.

        Present value.     When used with respect to oil and natural gas reserves, the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated, without giving effect to nonproperty-related expenses such as general and administrative expenses, debt service and future income tax expense or to depletion, depreciation, and amortization, discounted using an annual discount rate of 10%.

        Productive well.     A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

        Proved developed nonproducing reserves.     Proved developed reserves expected to be recovered from zones behind casing in existing wells.

        Proved developed producing reserves.     Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and able to produce to market.

        Proved developed reserves.     Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

        Proved reserves.     The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

        Proved undeveloped location.     A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

        Proved undeveloped reserves.     Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

        Recompletion.     The completion for production of an existing well bore in another formation from that in which the well has been previously completed.

        Reservoir.     A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

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        Royalty interest.     An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.

        3-D seismic.     Advanced technology method of detecting accumulations of hydrocarbons identified through a three-dimensional picture of the subsurface created by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

        Undeveloped acreage.     Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

        Working interest or WI.     The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

        Workover.     Operations on a producing well to restore or increase production.

ITEM 3.    LEGAL PROCEEDINGS

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

        David Blake, et al. v. Edge Petroleum Corporation —On September 19, 2005, David Blake and David Blake, Trustee of the David and Nita Blake 1992 Children's Trust, filed suit against us in state district court in Goliad County, Texas alleging breach of contract for failure and refusal to transfer overriding royalty interests to plaintiffs in several leases in the Nita and Austin prospects in Goliad County, Texas and failure and refusal to pay monies to Blake pursuant to such overriding royalty interests for wells completed on the leases. The plaintiffs seek relief of (1) specific performance of the alleged agreement, including granting of overriding royalty interests by us to Blake; (2) monetary damages for failure to grant the overriding royalty interests; (3) exemplary damages for his claims of business disparagement and slander; (4) monetary damages for tortious interference; and (5) attorneys' fees and court costs. Venue of the case was transferred to Harris County, Texas by agreement of the litigants. Our subsidiaries, Edge Petroleum Exploration Company, Edge Petroleum Operating Company and Edge Petroleum Production Company, were also added as defendants. We filed a counterclaim against plaintiff Blake and joined various related entities that are controlled by Blake, seeking lease interests in which we contend we had been wrongfully denied participation and also claiming that proprietary information was misappropriated. The parties have moved for summary judgment on each other's claims and counterclaims, which the trial court has denied as to both sides. In November 2007, we filed a separate motion for summary judgment based on the statute of frauds and; the court has not yet ruled on this separate motion. In June 2008, the plaintiffs filed a Sixth Amended Petition conditionally adding claims for certain prospects that had been previously settled by means of a Compromise and Settlement Agreement (the "Settlement Agreement"), entered in settlement of prior litigation among some of the parties, but only to the extent that rescission of the prior Settlement Agreement was being sought by us. We are not seeking rescission of the prior Settlement Agreement and responded accordingly in our 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. The trial, originally scheduled to begin September 10, 2007, has been reset several times, most recently for December 8, 2008, and will be reset in 2009 by the newly-elected judge of the 215th Judicial District Court. In December 2008, one of the Blake counter-defendants filed a motion to arbitrate, which motion has not been heard by the court. Extensive written discovery has occurred in the case, and the parties are engaging in fact and expert witness depositions.

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We have responded and will continue to respond aggressively to this lawsuit, and believe we have meritorious defenses and counterclaims.

        Diana Reyes, et al. v. Edge Petroleum Operating Company, Inc., et al. —On January 8, 2008, we were served with a wrongful death action filed in Hidalgo County, Texas. Plaintiffs allege negligence and gross negligence resulting from a fatality accident at the Slick State B-12 well site, on our Bloomberg Flores lease in Starr County, Texas. The plaintiffs are the widow and minor children of Mr. Reyes, who was killed in a one-car fatality accident on August 5, 2007. Mr. Reyes was an employee of Payzone Logging, a vendor of ours. In September 2008, the defendants in this case, including us, reached a settlement with the plaintiffs in the amount of $175,000, all of which was paid by third party insurance. Neither we nor our insurance carrier were required to contribute to the settlement pool. This matter was dismissed by the court on December 17, 2008.

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

        John Lemke, et al. v. Edge Petroleum Corporation —In October 2008, we were sued by alleged assignees of Continental Seismic over an alleged contract to receive a royalty of two-tenths of one percent in certain alleged areas developed for oil and gas in South Louisiana. We have filed an answer generally denying the allegations and raising the defenses of the statute of limitations bar and laches. No discovery has been served. The court recently entered a docket control order which establishes a discovery timetable and a trial date of November 30, 2009. We have not established a reserve with respect to this claim and we have not determined what, if any, our ultimate exposure might be in this matter. We will respond aggressively to this lawsuit, and believe we have meritorious defenses.

ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

        Our stockholders voted on the following matters at the Annual Meeting of Stockholders on December 29, 2008:

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        In addition to the election of the directors indicated above, the following directors continued as directors following the meeting: Thurmon M. Andress, John W. Elias, John Sfondrini, Robert W. Shower and David F. Work.

Executive Officers of the Registrant

        Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General Instruction G(3) to Form 10-K, the following information is included in Part I of this Form 10-K.

         John W. Elias has served as the Chief Executive Officer and Chairman of the Board of the Company since November 1998. From April 1993 to September 30, 1998, he served in various senior management positions, including Executive Vice President, of Seagull Energy Corporation, a company engaged in oil and natural gas exploration, development and production and pipeline marketing. Prior to April 1993, Mr. Elias served in various positions for more than 30 years, including senior management positions with Amoco Corporation, a major integrated oil and gas company. Mr. Elias holds a B.S. from Oklahoma University and is a graduate of the Advanced Management Program at Harvard University. Mr. Elias has more than 45 years of experience in the oil and natural gas exploration and production business. He is 68 years old.

         Gary L. Pittman has served as Executive Vice President and Chief Financial Officer of the Company since January 26, 2009. Prior to joining the Company, Mr. Pittman served as the Vice President of Special Projects at Tronox Incorporated from September 2008 to January 2009. Mr. Pittman has experience as Chief Financial Officer of four public companies of which three were E&P related. In addition, he has extensive experience with turnarounds and has also served as Vice President and Chief Financial Officer of Vermilion Companies from March 2008 to September 2008; as Chief Financial Officer from December 2002 to August 2007, Senior Vice President and Secretary from May 2006 to August 2007 and Treasurer from August 2004 to August 2007 of Pioneer Companies, Inc.; and as Vice President and Chief Financial Officer of Coho Energy, Inc. from 2000 to 2002. Mr. Pittman holds a B.A. and M.B.A. from Oklahoma University. He is 53 years old.

         John O. Tugwell has served as Chief Operating Officer and Executive Vice President since April 2005 and prior to that served as Chief Operating Officer and Senior Vice President of Production for the Company since March 2004. Prior to that, he served as Senior Vice President of Production since December 2001. Prior to that, Mr. Tugwell served as Vice President of Production since March 1997. He served as Senior Petroleum Engineer of the Company's predecessor corporation since May 1995. From 1986 to May 1995, Mr. Tugwell held various reservoir/production engineering positions with Shell Oil Company, most recently that of Senior Reservoir Engineer. Mr. Tugwell holds a B.S. in Petroleum Engineering from Louisiana State University. Mr. Tugwell is a registered Professional Engineer in the State of Texas. Mr. Tugwell is 45 years old.

Significant Employees

         Howard Creasey has served as the Senior Vice President of Exploration since October 2006 and prior to that as the Vice President of Exploration since October 2005. Before October 2005, Mr. Creasey was Chief Geologist for the Company since October 2003. From April 1999 until October 2003 he served as a Senior Staff Geologist for Devon Energy and its predecessor Ocean Energy. Prior to April 1999 for 14 years Mr. Creasey served as President and Exploration Geologist for Moss Rose Energy, Inc., a company he started in 1986. Mr. Creasey holds a B.S. in Geology from Stephen F. Austin State University, has been a member of the AAPG for over 25 years and is a Certified Geoscientist in the State of Texas. Mr. Creasey is 53 years old.

         Kirsten A. Hink has served as Chief Accounting Officer since July 2008 and Vice President and Controller of the Company since October 2003. She served as Controller of the Company from December 31, 2000 to October 2003. Prior to that time she served as Assistant Controller from June

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2000 to December 2000. Before joining Edge, she served as Controller of Benz Energy Inc., an oil and gas exploration company, from June 1998 to June 2000. Mrs. Hink received a B.S. in Accounting from Trinity University. Mrs. Hink is a Certified Public Accountant in the State of Texas. She is 42 years old.

         C.W. MacLeod has served as the Senior Vice President Business Development and Planning for the Company since April 2004 and Vice President Business Development and Planning for the Company since January 2002. From July 2008 to January 2009, he also served as our Acting Chief Financial Officer. From November 1999 to December 2001, he was Vice President—Investment Banking with Raymond James and Associates, Inc. From February 1990 to October 1999, Mr. MacLeod was a principal with Kirkpatrick Energy Associates, Inc., whose principal business was merger and acquisition services, capital arrangement and analytical services for the oil and gas producing industry. Mr. MacLeod was responsible for originating corporate finance and research products for energy clients. His previous experience includes positions as an independent petroleum geologist, a manager of exploration and production for an independent oil and gas producer and geologic positions with Ladd Petroleum Corporation and Resource Sciences Corporation. Mr. MacLeod graduated from Eastern Michigan University with a B.S. in Geology and earned his M.B.A. from the University of Tulsa. He is 58 years old.

         R. Keith Turner has served as Vice President of Land for the Company since September 2006. Before moving to the Land Department, Mr. Turner was a Staff Attorney in the Legal Department since 2003. Prior to joining the Company in 2003, Mr. Turner served in various capacities with Newfield Exploration Company, Fina Oil and Chemical Company and Torch Energy Advisors, Inc. He received a B.S. in Science from Stephen F. Austin State University and a J.D. degree from South Texas College of Law. Mr. Turner is 54 years old.

         Robert C. Thomas has served as Senior Vice President, General Counsel and Corporate Secretary since October 2006 and prior to that as Vice President, General Counsel and Corporate Secretary since March 1997. From February 1991 to March 1997, he served in similar capacities for the Company's corporate predecessor. From 1988 to January 1991, he was associate and acting general counsel for Mesa Limited Partnership in Amarillo, Texas. Mr. Thomas holds a B.S. degree in Finance and a J.D. degree in Law from the University of Texas at Austin. He is 55 years old.

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PART II

ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Price of and Dividends on Common Equity and Related Stockholder Matters.

        As of March 12, 2009, we estimate there were approximately 208 record holders of our common stock. Our common stock is listed on The NASDAQ Global Select Market ("NASDAQ") and traded under the symbol "EPEX". As of March 12, 2009, we had 28,836,927 shares of common stock outstanding and our closing price on NASDAQ was $0.11 per share. The following table sets forth, for the periods indicated, the high and low closing sales prices for our common stock as listed on NASDAQ.

        We have never paid a dividend on our common stock, cash or otherwise, and do not intend to in the foreseeable future. In addition, under our Revolving Facility, we are restricted from paying cash dividends on our common stock. The payment of future dividends, if any, will be determined by our Board of Directors in light of conditions then existing, including our earnings, financial condition, capital requirements, restrictions in financing agreements, business conditions and other factors. See ITEM 1A. "RISK FACTORS —We do not intend to pay dividends on our common stock and our ability to pay dividends on our common stock is restricted."

        There were no repurchases of securities during the fourth quarter of 2008.

Performance Graph

        The following performance graph compares the cumulative total stockholder return on the common stock to the cumulative total return of the Standard & Poor's 500 Stock Index ("S&P 500 Index") and an index composed of all publicly traded oil and gas companies identifying themselves by primary Standard Industrial Classification ("SIC") Code 1311 (Crude Petroleum and Natural Gas) for the period beginning December 31, 2003 and ending December 31, 2008.

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COMPARE 5-YEAR CUMULATIVE TOTAL RETURN
AMONG EDGE PETROLEUM CORPORATION, S&P 500 INDEX
AND SIC CODE 1311 INDEX

        The graph assumes that $100 was invested on December 31, 2003 in each of Edge common stock, the S&P 500 Index and the SIC Code 1311 companies and assumes that all dividends were reinvested:

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ITEM 6.    SELECTED FINANCIAL DATA

        The following table sets forth selected financial data regarding the Company as of and for each of the periods indicated. The following data should be read in conjunction with ITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS" and ITEM 8. "FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA" :

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(1)

As discussed in Notes 6 and 13 to our consolidated financial statements, we completed one significant property acquisition and public offerings of common and preferred stock in January 2007, which could affect the comparability of our results in 2007 to prior periods.

(2)

As discussed in Note 6 to our consolidated financial statements, we completed one significant property acquisition in December 2006 and various other working interest acquisitions throughout the year, which could affect the comparability of our results in 2006, and subsequent periods, to prior periods.

(3)

As discussed in Note 9 to our consolidated financial statements, in 2006 we discontinued the use of cash flow hedge accounting on our natural gas contracts. During 2006 and 2007, mark-to-market accounting treatment was applied to these contracts, which affects the comparability of our results in 2006, and subsequent periods, to prior periods.

(4)

We completed one property acquisition and one corporate acquisition in the fourth quarter of 2005, which affects the comparability of our results in 2005, and subsequent periods, to prior periods.

(5)

We completed a public offering of our common stock on December 21, 2004 and a significant property acquisition on December 29, 2004, therefore certain of our results in 2004 are not directly comparable to subsequent periods.

(6)

As discussed in Note 2 to our consolidated financial statements, we recorded an impairment of oil and natural gas properties during the third quarter of 2006 in the amount of $96.9 million ($63.0 million, net of tax) as a result of our full-cost ceiling test. The impairment of oil and natural gas properties during 2006 was primarily the result of a decline in natural gas prices at September 30, 2006, the date of impairment measurement for the full-cost ceiling test. In the third and fourth quarters of 2008, we recorded impairments of oil and natural gas properties in the amounts of $129.5 million ($84.2 million, net of tax) and $233.3 million ($215.8, net of tax), respectively, as a result of declines in commodity prices and negative revisions in our proved reserve quantities. No such impairment was necessary in the years 2003 through 2005 or 2007.

(7)

EBITDA is defined as net income (loss) before interest expense and amortization of deferred loan costs (net of interest income and amounts capitalized), income tax expense, depletion, depreciation and amortization and accretion expense. EBITDA is not adjusted for the full-cost ceiling test impairments recorded in 2006 and 2008. EBITDA is a financial measure commonly used in the oil and natural gas industry, but is not defined under accounting principles generally accepted in the United States of America ("GAAP"). EBITDA should not be considered in isolation or as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP or as a measure of a company's profitability or liquidity. Because EBITDA excludes some, but not all, items that affect net income, this measure may vary among companies. The EBITDA data presented above may not be comparable to a similarly titled measure of other companies. Our management believes that EBITDA is a meaningful measure to investors and provides additional information about our ability to meet our future liquidity requirements for debt service, capital expenditures and working capital. In addition, management believes that EBITDA is a useful comparative measure of operating performance and liquidity. For example, debt levels, credit ratings and, therefore, the impact of interest expense on earnings vary significantly between companies. Similarly, the tax positions of individual companies can vary because of their differing abilities to take advantage of tax benefits, with the result that their effective tax rates and tax expense can vary considerably. Finally, companies differ in the age and method of acquisition of productive assets, and thus the relative costs of those assets, as well as in the depreciation or depletion (straight-line, accelerated, units of production) method, which can result in considerable variability in depletion, depreciation and amortization expense between companies. Thus, for comparison purposes, management believes that EBITDA can be useful as an objective and comparable measure of operating profitability and the contribution of operations to liquidity because it excludes these elements.

(8)

Working Capital is defined as current assets less current liabilities.

(9)

As discussed in Note 11 to our consolidated financial statements, our outstanding debt was classified as current as of December 31, 2008, due to the amendment in the maturity date to June 30, 2009 as provided by the Amended Consent.

        We do not pay cash dividends on our common stock, and have not in the periods presented above; therefore, they are not presented in the selected financial data.

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ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        The following is a review of our financial position and results of operations for the periods indicated. Our Consolidated Financial Statements and Supplementary Information and the related notes thereto contain detailed information that should be referred to in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A").

GENERAL OVERVIEW

        Edge Petroleum Corporation ("Edge", "we" or the "Company") is a Houston-based independent energy company that focuses its exploration, development, production, acquisition and marketing activities in selected onshore basins of the United States. In late 1998, we undertook a top-level management change and began a shift in strategy from pure exploration, which focused more on prospect generation, to a strategy which focused on a balanced program of exploration, exploitation and development and acquisition of oil and gas properties. In late 2007, in an attempt to enhance shareholder value we began to assess our strategic alternatives and have subsequently expanded this process to include a further evaluation of both our financial and strategic alternatives in late 2008 and continuing into 2009. Our current primary focus is on capital preservation and resolving the uncertainty and challenges we face.

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

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

•

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



•

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



•

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



•

Acquisitions and Divestitures —information about significant changes in our business structure.



•

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



•

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



•

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



•

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



•

Risk Management Activities—Derivatives & Hedging —supplementary information regarding our price-risk management activities.

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•

Tax Matters —supplementary discussion of income tax matters.



•

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

OUTLOOK AND REVIEW OF FINANCIAL AND STRATEGIC ALTERNATIVES

        On December 18, 2007, we announced the hiring of a financial advisor to assist our Board of Directors with an assessment of strategic alternatives. On February 7, 2008, we provided an update on the strategic alternatives process and announced publicly that we would implement a process to explore a merger or sale of the company. As a result of the strategic alternatives process, on July 14, 2008, we entered into an Agreement and Plan of Merger (the "Merger Agreement") with Chaparral Energy, Inc. ("Chaparral") and Chaparral Exploration, L.L.C., a Delaware limited liability company and wholly owned direct subsidiary of Chaparral ("Sub"), whereby we would merge with and into Sub. The Merger Agreement was unanimously approved by our Board of Directors and Chaparral's Board of Directors and stockholders. To provide additional funding for the transaction, Chaparral expected to sell 1.5 million shares of its Series B convertible preferred stock, par value $0.01 per share for $150 million in a private sale to Magnetar Financial LLC, on behalf of itself and one or more of its affiliates and assigns (collectively, "Magnetar"). On October 23, 2008, we adjourned our annual meeting of stockholders and announced our plans to reconvene the meeting on December 4, 2008, when our common stockholders would vote on the adoption of the Merger Agreement. The adjournment to the later date was intended to allow additional time for Edge common stockholders to receive and consider additional information regarding the proposed merger with Chaparral. On December 3, 2008, we announced that we would reconvene the annual meeting of stockholders on December 29, 2008. 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. On December 17, 2008, we announced the termination of the 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. As a result, after consultation with our legal and financial advisors, our Board of Directors approved a merger termination agreement with Chaparral and a termination and settlement agreement among us, Chaparral and Magnetar. Pursuant to the termination agreements, Magnetar reimbursed Chaparral $5.0 million for certain expenses, of which $1.5 million was paid to us at Chaparral's direction, of which we paid $0.3 million to our then-financial advisor, Merrill Lynch.

        We are currently undertaking the evaluation and assessment of various financial and strategic alternatives, which may include the sale of some or all of our assets, a merger or other business combination involving the Company, restructuring or recapitalization of the Company to address our liquidity issues and the Deficiency under our Revolving Facility (see discussion below). We have retained an investment banking firm to assist further in the evaluation of our strategic and financial alternatives.

        During January 2009, we announced that the lenders ("Lenders") to our Fourth Amended and Restated Credit Agreement (as amended, the "Revolving Facility") had completed their borrowing base redetermination and reduced our borrowing base to $125 million, resulting in a $114 million borrowing base deficiency (the "Deficiency"). Pursuant to the terms of the Revolving Facility, we elected to prepay the Deficiency in six equal monthly installments, with the first $19 million installment being due on February 9, 2009. On February 9, 2009, we entered into a Consent and Agreement (the "February Consent") among us and the Lenders, 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

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the last of the six $19 million installment payments to be due on August 10, 2009. In connection with the February Consent, we agreed to prepay $5.0 million of our 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. Each of the prepayments will be applied on a pro rata basis to reduce the remaining six $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 provides, among other things, (1) that we will 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 will be an event of default (i) if we fail 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 are in default under or our hedging arrangements have been terminated or cease to be effective without the prior written consent of our Lenders, (3) that our advances under the Revolving Facility will 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% as of March 16, 2009), (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 eliminates the six $19 million deficiency payments which were contemplated by the February Consent and the March Consent. To comply with the terms of the Amended Consent, we anticipate that we will need to (i) sell select individual assets prior to May 31, 2009 to enable us to make the $25 million payment which is due on May 31, 2009, and/or (ii) negotiate a commitment letter with a new lender or group of lenders prior to May 15, 2009 in an amount sufficient to repay all of our obligations under the Revolving Facility on or before June 30, 2009, and/or (iii) have negotiated the sale, merger or other business combination involving us which results in the repayment of all of our obligations under the Revolving Facility prior to May 15, 2009 and to have closed such transaction on or before June 30, 2009. The Amended Consent limits the making of capital expenditures and we anticipate a severe curtailment of our drilling plans and other capital expenditures in 2009.

        If we breach any of the provisions of the Amended Consent or the Revolving Facilities, our Lenders will be entitled to declare an event of default, at which point the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, would become immediately due and payable. In any event, the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, will be payable on June 30, 2009 unless earlier paid or a further extension with respect to payment is negotiated with our Lenders. Our Lenders may take action to enforce their rights with

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respect to the outstanding obligations under the Revolving Facility. Because substantially all of our assets are pledged as collateral under the Revolving Facility, if our Lenders declare an event of default, they would be entitled to foreclose on and take possession of our assets. In such an event, we may be forced to liquidate or to otherwise seek protection under Chapter 11 of the U.S. Bankruptcy Code. These matters, as well as the other risk factors related to our liquidity and financial position raise substantial doubt as to our ability to continue as a going concern. See ITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS —LIQUIDITY AND CAPITAL RESOURCES— REVOLVING FACILITY." With respect to our compliance with the Amended Consent, there can be no assurance that we will be able to further negotiate the terms of the Amended Consent or negotiate a further restructuring of the related indebtedness or that we will be able to make any required payments when they become due. Moreover, there can be no assurance that we will be successful in our efforts to comply with the terms of the Amended Consent, including our ongoing efforts to evaluate and assess our various financial and strategic alternatives (which may include the sale of some or all of our assets, a merger or other business combination involving the Company, or the restructuring or recapitalization of the Company). If such efforts are not successful, we may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

        Going Concern —In addition to the Deficiency under our Revolving Facility, the capital expenditures required to maintain and/or grow production and reserves are substantial. Our stock price has significantly declined over the past year which makes it more difficult to obtain equity financing on acceptable terms to address our liquidity issues. In addition, we are reporting negative working capital at December 31, 2008 and a third consecutive year of net losses for the year ended December 31, 2008, which is largely the result of impairments of our oil and natural gas properties. Therefore, there is substantial doubt as to our ability to continue as a going concern for a period longer than the current fiscal year. Our ability to continue as a going concern is dependent upon the success of our financial and strategic alternatives process, which may include the sale of some or all of our assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company. Until the possible completion of the financial and strategic alternatives process, our future remains uncertain and there can be no assurance that our efforts in this regard will be successful.

        Our consolidated financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which implies we will continue to meet our obligations and continue our operations for the next twelve months. Realization values may be substantially different from carrying values as shown, and our consolidated financial statements do not include any adjustments relating to the recoverability or classification of recorded asset amounts or the amount and classification of liabilities that might be necessary as a result of this uncertainty. Our independent auditors have included an explanatory paragraph in their report on our consolidated financial statements that raises substantial doubt about our ability to continue as a going concern. See ITEM 8. "FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA —Report of the Independent Registered Accounting Firm."

        Our outlook and the expected results described above are both subject to change based upon factors that include, but are not limited to, drilling results, commodity prices, the results of our financial and strategic alternatives process, access to capital, the acquisitions market and factors referred to in "FORWARD LOOKING INFORMATION."

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

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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 the second half of 2008, a world-wide economic recession and oversupply of natural gas in North America led to an unprecedented decline in oil and natural gas prices, with oil falling by more than $100.00 per barrel and natural gas falling more than $8.00 per Mcf from their peaks in July 2008.

        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. 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. The prospect of continued low commodity prices and disproportionately high 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 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. This was a factor in our 2008 results, which reflected a 24% lower proved reserve base at year-end. We were unable to replace the production we generated due to our reduced capital spending program and higher drilling and operating costs. This will continue to be a factor in 2009 as we operate under a severely limited capital and operating budget.

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

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

        The growing global economic crisis created an environment of uncertainty during the third and fourth quarters of 2008. We are unable to predict the impact on our business of a continued decline in commodity prices and the global economy. Possible negative impacts, among others, could include 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. As a result of the strategic alternatives process that began in late 2007 (see discussion above), our Board

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approved a reduced capital expenditure budget for 2008, while we assessed the potential sale or merger of the Company. This affected our spending in the third and fourth quarters of 2008.

        More recently, in connection with our ongoing financial and strategic alternatives process and our liquidity issues resulting from the Deficiency under our Revolving Facility and the related Amended Consent, we have operated and will continue to operate with a severely limited capital spending program in 2009 as we continue to pursue the sale of some or all of our assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company. Our strategy is currently to continue under a severely limited capital and operating budget, thereby reducing our normal exploration and development activities as we seek to preserve liquidity and resolve the uncertainty and challenges that we face as we pursue various financial and strategic alternatives.

        We normally hedge our exposure to volatile oil and natural gas prices on a portion of our expected production to reduce price risk. As a result of changes to our forecasted 2008 production and the impact of certain asset divestitures, both of which reduced production as compared to that expected at the time we entered into the derivative contracts, we had approximately 115% and 190% of our 2008 natural gas and crude oil production, respectively, covered by derivative contracts. This overhedged position exposed us to greater risk of commodity price increases because at times we did not have the physical production cash inflows to offset the losses incurred on the portion of the contracts that were overhedged. During September and October 2008, we entered into two new contracts for certain fourth quarter 2008 production that were intended to offset a portion of the volumes that were overhedged and thereby reduce our exposure to significant increases in natural gas and crude oil prices.

ACQUISITIONS AND DIVESTITURES

        Acquisitions —We became increasingly active in acquisitions in recent years. In the past, we have looked to acquisitions to enable us to achieve our growth objectives. Acquisitions add meaningful incremental increases in reserves and production and may range in size from acquiring a working interest in non-operated producing property to an entire field or company. Unlike drilling capital, which is planned and budgeted, acquisition capital is neither budgeted nor allocated. Specific timing and size of acquisitions cannot be predicted, but in light of current conditions, we do not expect to make any acquisitions in the coming year.

        January 2007 Acquisition —During the first quarter of 2007, we completed the largest acquisition in our history. We acquired oil and natural gas properties located in 13 counties in south and southeast Texas, exploration rights, leasehold acreage, gathering facilities and gathering pipelines from a privately held company (the "January 2007 Acquisition"). This acquisition had a substantial impact on our reserves, production revenues, operating costs, and property base. The final adjusted cash purchase price was $384.4 million. We financed the purchase price of the January 2007 Acquisition through public offerings of common and preferred stock (see Notes 13 and 14 to our consolidated financial statements) and borrowings under our Revolving Facility (see Note 11 to our consolidated financial statements). We also capitalized approximately $1.4 million in other direct costs resulting from the acquisition and assumed asset retirement obligation ("ARO") liabilities of $0.9 million.

        As part of this acquisition, we also acquired a 12.5% working interest in an approximate 160 square mile 3-D exploration area with approximately 55,000 gross acres of leases and options located in the Yates Ranch/Hostetter project area in McMullen and Duval Counties in south Texas. During the third quarter 2007, we elected to terminate this exploration venture. The effective date of termination for this venture was October 2, 2007. In exchange for returning all 3-D seismic data covering the area of mutual interest, the privately held company refunded our payments since January 2007 related to this exploration venture. In October 2007, we received $5.5 million, including the $5.0 million initial price paid for the venture and $0.5 million in expenses related to the venture, which were incurred and paid to the privately held company from January to September 2007.

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        Chapman Ranch Acquisition 2006 —On December 12, 2006, we executed an agreement to acquire certain working interests in the Chapman Ranch Field in Nueces County, Texas from Kerr-McGee Oil & Gas Onshore LP ("Kerr-McGee"), a wholly-owned subsidiary of Anadarko Petroleum Corporation. Upon the closing of this acquisition on December 28, 2006, we assumed the role of operator of the Chapman Ranch Field and added to our existing working interest position in this field which we initially acquired in connection with two other acquisitions in late 2005. The final adjusted purchase price was approximately $25.3 million (including a previously paid deposit of $2.6 million) as a result of adjustments for the results of operations between the December 1, 2006 effective date and the December 28, 2006 closing date, and other purchase price adjustments. We financed the purchase price of this acquisition through $24.0 million in borrowings under our then-existing credit facility.

        Divestitures —We regularly review our asset base for the purpose of identifying non-core assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. While in the past we have not generally disposed of assets solely for the purpose of reducing debt, in connection with our ongoing financial and strategic alternatives process, we are actively pursuing the possible sale of some or all of our assets or other business combinations involving the Company. We believe that we will need to make significant divestitures in 2009 in order to comply with the terms of the Amended Consent. During 2008, we completed sales of a pipeline and certain working interests in approximately 120 properties located in Texas and Mississippi to various buyers for aggregate proceeds of approximately $19.2 million, which we used to reduce outstanding debt. During January 2007, we divested a portion of our interest in a Louisiana well for $1.1 million. During 2006, we sold our Buckeye properties in Live Oak County, Texas for $0.6 million.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

        The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, contingent assets and liabilities and the related disclosures in the accompanying consolidated 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 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. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the economics of producing the reserves may change and therefore the estimate of proved reserves also may change. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our consolidated financial statements.

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

        "Ceiling" Test —The full-cost method of accounting for oil and 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 registrant to elect to use the subsequent date's higher prices in calculating the full-cost ceiling. We made this election for the third and fourth quarters of 2007. To the extent that our capitalized costs (net of accumulated depletion, impairments 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 2007 to 2008, and the average oil, NGL and natural gas prices at the balance sheet date as of December 31, 2008 were also lower at $44.60 per barrel, $26.76 per barrel and $5.71 per MMBtu, respectively. As a result, we recorded a ceiling test impairment during the three months ended December 31, 2008 of $233.3 million ($215.8 million, net of tax). This impairment, along with the impairment recorded during the third quarter of 2008 of $129.5 million ($84.2 million, net of tax), will significantly affect the comparability of results between the 2008 and 2007 periods. During the year ended December 31, 2007, we elected to use subsequent pricing as of January 20, 2008 of $90.57 per barrel of oil and $8.42 per MMBtu. As a result, no ceiling test impairment was required at December 31, 2007. During the year ended December 31, 2006, we recorded a ceiling test impairment of $96.9 million ($63.0 million, net of tax).

        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 year by approximately 10%.

        "Ceiling" Test —Factors that contribute to a ceiling test impairment include the price used to calculate the reserve limitation threshold and reserve quantities. A significant reduction in prices at a measurement date could trigger a full-cost ceiling impairment. We recorded an impairment of $233.3 million ($215.8 million, net of tax) at December 31, 2008. A 10% increase or decrease in prices would have decreased or increased our impairment by approximately 20%, net of tax, respectively. Although our hedging program is intended to mitigate the economic impact of any significant price decline, it did not impact our ceiling test at December 31, 2008 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 an 8% decrease in the impairment taken as a result of the low prices at the measurement date falling below the price floors. A 10% increase or decrease in reserve volume would have decreased or increased the impairment calculated at December 31, 2008 by approximately 10%. Should commodity prices continue to decrease in 2009 or we further revise our reserve quantities, the potential for additional ceiling test impairments at a future date exists.

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        Nature of Critical Estimate Item: Asset Retirement Obligations —We have certain obligations to remove tangible equipment and restore land at the end of oil and natural gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells.

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Prior to the adoption of Statement of Financial Accounting Standards ("SFAS") No. 143, Accounting for Asset Retirement Obligations , the costs associated with this activity were capitalized to the full-cost pool as they were incurred and charged to income through depletion expense. SFAS No. 143 significantly changed the method of accruing for costs an entity is legally obligated to incur related to the retirement of fixed assets ("asset retirement obligations" or "ARO"). Primarily, SFAS No. 143 requires us to estimate asset retirement costs for all of our assets, 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. new well drilled or acquired, we add a layer to the ARO liability. We accrete the liability layers quarterly using the applicable period-end effective credit-adjusted-risk-free rates for each layer. Should either the estimated life or the estimated abandonment costs of a property change upon our quarterly review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost (included in the full-cost pool); therefore, abandonment costs will almost always approximate the estimate. When well obligations are relieved by sale of the property or plugging and abandoning the well, the related liability and asset costs are removed from our balance sheet.

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

        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.

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        Nature of Critical Estimate Item: Income Taxes —In accordance with SFAS No. 109, Accounting for Income Taxes, we have recorded a deferred tax asset and liability to account for the expected future tax benefits and consequences, respectively, of events that have been recognized in our consolidated financial statements and our tax returns. There are several items that result in deferred tax asset and

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liabilities on the balance sheet, the largest of which are deferred liabilities attributable to book basis in excess of tax 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 consolidated financial statements. Additionally, in accordance with Financial Accounting Standards Board ("FASB") Interpretation 48, Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109 ("FIN 48"), we have recorded a liability of $0.1 million associated with uncertain tax positions. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We are required to determine whether it is more likely than not (a likelihood of more than 50 percent) that a tax position will be sustained upon examination, including resolution of 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 our consolidated 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 consolidated financial statements, as was done in the fourth quarter of 2008. 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 fourth quarter of 2008, we recorded a valuation allowance of approximately $110 million as a result of our anticipated inability to utilize all of our deferred tax assets.

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        Nature of Critical Estimate Item: Derivative and Hedging Activities —Due to the instability of oil and natural gas prices, from time to time, we may enter 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 SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended), all derivatives,

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other than those that meet the normal purchases and sales exception, are recorded on the balance sheet at fair value. See ITEMS 1 AND 2. "BUSINESS AND PROPERTIES —DERIVATIVES."

        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 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 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 hedges. We currently obtain the fair value of our positions from our counterparties. Our practice of relying on our counterparties who are more specialized and knowledgeable in preparing these complex calculations reduces our management's input. It also approximates the fair value of the contracts as that 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 for 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 revenue on the statement of operations rather than in OCI on the balance sheet.

        Effect if different assumptions used:     At December 31, 2008, a 10% change in the commodity price per unit would cause the fair value total of our derivative financial instruments to increase or decrease by approximately $1.5 million. Had we applied cash flow hedge accounting treatment to all of our derivative contracts outstanding at December 31, 2008, our net loss to common stockholders for the year would have been $236.2 million, or $8.30 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 year ended December 31, 2008 of $339.4 million, or $11.89 basic and diluted loss per share.

RESULTS OF OPERATIONS

        This section includes discussion of our 2008, 2007 and 2006 results of operations. 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.

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Revenue and Production

        Our primary source of production and revenue is natural gas. For the years ended December 31, 2008, 2007 and 2006, our product mix contributed the following percentages of revenues and production:

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(1)

Includes effect of derivative transactions.

(2)

Excludes effect of derivative transactions.

        The following table summarizes production volumes, average sales prices and operating revenue for our oil and natural gas operations for the periods indicated.

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(1)

Prices are calculated based on whole numbers, not rounded numbers.

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(2)

Excludes the effect of derivative transactions.

(3)

Includes the effect of derivative transactions.

*

Not meaningful.

        Production —For the year ended December 31, 2008, production volumes decreased as compared to the same 2007 period primarily due to normal production declines, asset sales completed during early 2008 and decreased capital re-investment in replacing production as compared to historical levels. To a lesser extent, Hurricane Ike struck in mid-September 2008, causing some wells to be shut-in during the third and fourth quarters of 2008 resulting in additional production declines for all commodities. The growth in natural gas production in 2007 was primarily due to the addition of new assets acquired in the January 2007 Acquisition and to a lesser extent the additional assets acquired in the Chapman Ranch Field in December of 2006. Additionally, new wells drilled during 2007 in the Vicksburg and Deep Frio project areas of Texas and in southeast New Mexico contributed to the growth. Partially offsetting these increases were declines in Mississippi, some of our Queen City and Lobo properties in Texas, and on older wells in the southeast New Mexico project area. Additionally, in late 2006 and early 2007, we entered into natural gas processing agreements for our Chapman Ranch production and our non-operated Queen City production in Jim Hogg County, which agreements contributed a portion of the increase in NGL production in 2007 as compared to 2006. The following summarizes our average daily production volumes:

        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. Although commodity prices were very high during the second and third quarters of 2008, prices in the fourth quarter of 2008 decreased significantly, which lead to unrealized gains in our year-end derivative valuations and the ceiling test impairment (see discussions below).

        Natural gas revenue —The overall decrease in production for 2008 compared to 2007 resulted in an decrease in revenue of approximately $36.5 million (based on 2007 comparable period pre-derivative prices). Excluding the effect of derivative activity, the average natural gas sales price for production in 2008 was higher than 2007, which resulted in increased revenue of approximately $22.3 million (based on 2008 production). The overall increase in production for 2007 compared to 2006 resulted in an increase in revenue of approximately $24.6 million (based on 2006 comparable period pre-derivative prices). Average prices received in 2007 were slightly lower than 2006, resulting in decreased revenue of approximately $0.4 million (based on 2007 production). See below for a discussion of the impact of natural gas derivatives on prices and revenue.

        NGL revenue —The overall decrease in production for 2008 compared to 2007 resulted in an decrease in revenue of approximately $3.1 million (based on 2007 comparable period prices). The

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average NGL sales price for production in 2008 was higher than 2007, which resulted in increased revenue of approximately $4.9 million (based on 2008 production). The overall increase in production for 2007 compared to 2006 resulted in an increase in revenue of approximately $10.6 million (based on 2006 comparable period prices). Average prices received in 2007 were 57% higher than 2006, resulting in increased revenue of approximately $9.2 million (based on 2007 production). We have not placed derivative transactions on our NGL production in the past.

        Crude oil and condensate revenue —The overall decrease in production for 2008 compared to 2007 resulted in a decrease in revenue of approximately $11.7 million (based on 2007 comparable period pre-derivative prices). Excluding the effect of derivative activity, the average crude oil and condensate sales price for production in 2008 was higher than 2007, which resulted in increased revenue of approximately $9.0 million (based on 2008 production). The overall increase in production for 2007 compared to 2006 resulted in an increase in revenue of approximately $7.2 million (based on 2006 comparable period pre-derivative prices). Average prices received in 2007 were 12% higher than 2006, resulting in increased revenue of approximately $3.6 million (based on 2007 production). See below for a discussion of the impact of crude oil derivatives on prices and revenue.

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

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summarizes the various components of the total gain or loss on derivatives for each of the periods indicated and the impact each component had on our realized prices:

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(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. 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. Our overall 2008 derivative position exceeded our total 2008 production, due to changes in forecasted production and certain asset divestitures. Although we took steps in the fourth quarter of 2008 to reduce the overhedge exposure, the position exposed us to greater losses during those periods of high prices in the second and third quarters of 2008. For additional discussion of the overhedge position, see Note 9 to our consolidated financial statements.

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Costs and Operating Expenses

        The table below presents a detail of expenses for the periods indicated:

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*

Not meaningful

        Oil and natural gas operating expenses —Oil and natural gas operating expenses include direct operating costs, delivery commitment fees, repairs and maintenance and workover expenses. In 2008 these expenses were slightly lower than 2007 due to the sale of certain non-core assets during early 2008. Partially offsetting the decrease from sold properties were increases in costs at Chapman Ranch, Flores/Bloomberg and Encinitas fields and a portion of the liability we recorded on our delivery commitment to Frontier in the amount of $0.7 million (see Note 2 to our consolidated financial statements). In 2007, oil and natural gas operating expenses were significantly impacted by the January 2007 Acquisition, which contributed 70% of the increase in costs (averaging $0.58 per Mcfe for the year) from 2006 to 2007. The increasing cost structure in 2007 as compared to 2006 resulted from added costs for compression, expensed workovers and salt-water disposal as well as inflation in our industry. The increase in expenses was also affected to a lesser extent by the Chapman Ranch acquisition in December of 2006. Operating expenses averaged $0.98 per Mcfe, $0.71 per Mcfe and $0.53 per Mcfe for the years ended December 31, 2008, 2007 and 2006, respectively.

        Severance and ad valorem taxes —Severance taxes are levied directly on our non-hedge revenue dollars, therefore swings in revenues will impact our severance tax expense. The severance tax rate realized in the years ended December 31, 2008, 2007 and 2006 was 5.6%, 4.8% and 5.4%, respectively. We recorded severance tax abatements related to prior year periods during early 2007, which effectively lowered the 2007 rate realized and total expense. The rate realized also changes as a result of the changing mix of our production locations. Ad valorem tax expense for 2008 was 85% lower than the prior year because we reduced our estimates in 2008 as a result of the actual 2007 costs coming in lower than originally anticipated in 2007 accrual estimates. In addition, the 2008 ad valorem tax valuations, which are based on reserves, were lower in 2008 than in the prior year which resulted in lower costs for 2008. Ad valorem costs increased in 2007 as compared to 2006 due to the addition of properties acquired in January 2007. If not for the January 2007 Acquisition, ad valorem tax expense for the year ended December 31, 2007 would have decreased by approximately 50% as compared to the year ended December 31, 2006. On an equivalent basis, severance and ad valorem taxes averaged

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$0.56 per Mcfe, $0.54 per Mcfe and $0.53 per Mcfe for the years ended December 31, 2008, 2007 and 2006, respectively.

        Depletion, depreciation and amortization ("DD&A") and accretion expense —Depletion expense on a unit of production basis for the years ended December 31, 2008, 2007 and 2006 was $5.08 per Mcfe, $3.77 per Mcfe and $3.51 per Mcfe, respectively. The depletion rate has increased in recent years due to significant property costs for both drilling and exploration activities, as well as our acquisition program, without a corresponding increase in reserves. Additionally, negative revisions to our proved reserves at year-end 2007 increased our depletion rate. We expect the substantial impairments taken in 2008 to reduce our 2009 depletion rate.

        Depreciation expense of other assets is related to our executive office leasehold improvements, furniture and fixtures, computer equipment and software and pipelines that transport third-party gas. Depreciation expense related to other assets increased from 2007 to 2008 due to our office expansion that occurred in the latter half of 2007, which included leasehold improvements, new office furniture and equipment and computers and software. Depreciation expense increased from 2006 to 2007 primarily because of pipelines acquired in the January 2007 Acquisition.

        Accretion expense on our ARO liability increased in each year due to the addition of new obligations associated with wells added each year, including the large acquisition completed in January 2007 which had a significant impact on the comparison between 2006 and 2007. Accretion expense is calculated using the interest method of allocation, which calculates interest on the cumulative balance such that the interest increases with each subsequent period.

        Impairment of oil and natural gas properties —At December 31 and September 30, 2008 we recorded non-cash full-cost ceiling test impairments of oil and natural gas properties in the amount of $233.3 million ($215.8 million net of tax) and $129.5 million ($84.2 million net of tax), respectively, as discussed in Note 2 to the consolidated financial statements. These write-downs were the result of declines in commodity prices and negative revisions in our proved reserve quantities at year-end 2007 and during 2008. We recorded a non-cash full-cost ceiling test impairment of oil and natural gas properties in the amount of $96.9 million ($63.0 million, net of tax) during 2006 as a result of declines in natural gas prices at September 30, 2006. No such impairment was recorded in 2007.

        General and administrative ("G&A") expenses —In 2008, we recorded costs associated with the strategic alternatives process, the proposed merger with Chaparral and the retention bonus program adopted during the second quarter of 2008. We incurred costs of approximately $2.5 million related to the strategic alternatives process and proposed merger with Chaparral and approximately $2.8 million of retention bonuses. Other increases in total G&A expense for 2008 as compared to 2007 included health insurance, rent expense, and maintenance contracts. Partially offsetting these increases were decreases in entertainment costs, Board compensation, professional fees such as audit and legal unrelated to the strategic alternatives process, and bad debt expense. We also received a $1.5 million settlement from Magnetar for the termination of the proposed merger with Chaparral (see "Outlook and Review of Financial and Strategic Alternatives") of which we paid $0.3 million to our then-financial advisor, Merrill Lynch. Our salary and benefits comprise approximately 80% of total G&A expense in each year and therefore salary and benefits typically drive increases and decreases. In 2008, our salary and benefits costs decreased in comparison to 2007 as a result of the departure of several employees. In 2007, we added 21 new employees and seven during 2006 as a result of our growth, which caused an overall increase in salary and personnel related costs for 2007 as compared to 2006. Other cost increases during 2007 include rent expense for our corporate office expansion and professional service fees, offset by decreased costs for our Board of Directors and franchise taxes. Franchise taxes in 2006 were higher than the subsequent years as a result of payment of a franchise tax settlement to the State of Texas of approximately $0.2 million. Also in 2006 we recorded a litigation settlement of $0.2 million that was not repeated in the subsequent periods presented here. In general,

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G&A expense is reduced by capitalized G&A and overhead reimbursement fees, both of which increased in each year. We capitalized $4.1 million, $4.0 million and $3.0 million of G&A costs in 2008, 2007 and 2006, respectively. For the years ended December 31, 2008, 2007 and 2006, overhead reimbursement fees reduced G&A expense by approximately $1.4 million, $1.2 million, and $0.4 million, respectively. G&A expenses, excluding non-cash share-based compensation costs, on a unit of production basis for the years ended December 31, 2008, 2007 and 2006 were $0.89 per Mcfe, $0.60 per Mcfe and $0.68 per Mcfe, respectively.

        A portion of G&A expense is attributable to share-based compensation costs related to restricted stock awards granted in the past. Restricted stock awards vest over a three to four year period. For the years ended December 31, 2008, 2007 and 2006 we recorded $1.6 million, $3.0 million and $2.0 million. The increase in compensation for restricted stock awards in 2007 as compared to 2006 is related to additional restricted stock awards granted in conjunction with our increase in employees from 2006 to 2007. A large portion of the decrease in 2008 was due to forfeitures of these grants by departing employees.

        During 2008, we recorded bad debt expense of $0.1 million related to trade and joint interest accounts receivable that we felt were uncollectible. During 2007, we recorded bad debt expense of $0.5 million related to the ongoing Golden Prairie/Duke dispute that we no longer felt we could collect as we exhausted our legal efforts on this matter. This was partially offset by a reduction of bad debt expense of $0.3 million for a receivable that was reserved as uncollectible in 2001, but recovered during the fourth quarter of 2007. There was no bad debt expense recorded in 2006. Historically we have not experienced significant credit losses on our receivables, but we cannot ensure that similar such losses may not be realized in the future.

        Upon adoption of SFAS No. 123(R), as discussed in Notes 2 and 19 to our consolidated financial statements, during 2006, we recorded $68,937 in compensation expense for stock options that had not vested as of adoption of SFAS No. 123(R). Those options have since vested and we have not issued new options since 2004. Therefore, we did not record any stock option expense in 2008 and 2007 nor do we expect to record expense related to stock options in the near future.

        Other income (expense) —At December 31, 2008, 2007 and 2006 our unproved property balance was $16.4 million, $34.9 million, and $57.6 million, respectively, which provided for capitalization of a portion of our gross interest costs. We incurred higher gross interest costs for the years ended December 31, 2008 and 2007 than for 2006 due to higher commitment fees on our Revolving Facility and higher outstanding debt balances. The year ended December 31, 2007 also includes a one time commitment fee of $1.3 million paid to our lender for our unused bridge loan facility in January 2007 (see Note 11 to our consolidated financial statements). The year ended December 31, 2006 also includes interest paid on our franchise tax settlement in 2006 of approximately $40,150. Interest costs on the franchise tax settlement were not subject to capitalization. The table below details our interest expense, capitalized interest and weighted average debt for each of the periods indicated:

        Included in other income (expense) is amortization of deferred loan costs of $1.4 million and $1.0 million associated with our Revolving Facility for the years ended December 31, 2008 and 2007,

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respectively, and $0.2 million associated with our then-existing credit facility for the year ended December 31, 2006. These costs were higher in 2008 and 2007 due to the higher costs associated with our Revolving Facility compared to our prior credit facility. During 2008, we also wrote off approximately 25% of the remaining costs in relation to the decrease in the borrowing base.

        Also included in other income (expense) was interest income, which totaled $0.2 million, $0.4 million, and $0.2 million for the years ended December 31, 2008, 2007 and 2006, respectively. The interest is earned on daily cash invested in overnight money market funds. We had increased cash on hand in 2007 providing for the increased interest income.

        Income tax expense (benefit) —We are subject to state and federal income taxes, but we are not in a federal income tax paying position as a result of deducting intangible drilling costs ("IDC") that reduce our taxable income for income tax purposes and NOL carryforwards that offset any remaining taxable income. A deferred income tax benefit of $15.8 million and $21.6 million were recorded for the years ended December 31, 2008 and 2006, respectively. A deferred income tax provision of $3.7 million was recorded for the year ended December 31, 2007. Due to valuation allowances and changes in amounts of permanent tax differences, including meals and entertainment and other expenses, our effective tax rate also changes from time to time. The effective rate for 2008 was 4.5% due primarily to a deferred tax valuation allowance of approximately $110.2 million recorded in the fourth quarter of 2008. The effective rate was 36.2% in 2007 and 34.3% in 2006. We were required to make alternative minimum tax payments of $94,100 for the year ended December 31, 2006 only.

        Preferred stock dividends —Our Board of Directors declared quarterly dividends on our 5.75% Series A cumulative convertible perpetual preferred stock (the Convertible Preferred Stock") in 2007 and 2008. Our Board of Directors elected not to declare or make payments of the 2008 fourth quarter dividend on the outstanding Convertible Preferred Stock because of our current liquidity situation (see "Liquidity and Capital Resources" section below). As of December 31, 2008, preferred dividends in arrears amounted to $1.7 million, or $0.60 per share, on the Convertible Preferred Stock. The Convertible Preferred Stock was issued in connection with a public offering in January 2007, therefore no comparable dividends were paid in 2006.

        Loss per share —For the years ended December 31, 2008, 2007 and 2006, we reported a net loss to common shareholders and thus a loss per share. Basic weighted average shares outstanding increased from approximately 17.4 million at December 31, 2006 to 27.6 million at December 31, 2007 and to 28.7 million at December 31, 2008. There were minimal increases due to options exercised and vesting of restricted stock during each of these periods, but the primary cause of the significant increase from 2006 to 2007 was the public offerings of common stock and preferred stock in January 2007 that was made to partially finance the January 2007 Acquisition. We issued approximately 10.9 million shares of common stock. We also issued approximately 2.9 million shares of the Convertible Preferred Stock, which, when converted, have an anti-dilutive effect of approximately 8.7 million shares of common stock, and therefore, are not included in the calculation of diluted earnings per share for the year ended December 31, 2007 and 2008. Diluted earnings per share calculations in loss periods do not include certain shares that would result in an anti-dilutive effect on earnings per share.

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LIQUIDITY AND CAPITAL RESOURCES

        Historically, our primary ongoing source of capital was the cash flow generated from our operating activities supplemented by borrowings under our Revolving Facility. We currently do not have any available borrowing capacity under our Revolving Facility (see "Revolving Facility" below for additional discussion) and we have a $25 million payment due 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. 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. This was a factor in our 2008 results, which reflected a 24% lower proved reserve base at year-end. We were unable to replace the production we generated due to our reduced capital spending program and higher drilling and operating costs. In addition to our existing rapid production decline curve, this will continue to be factor in 2009 as we operate under a severely limited capital and operating budget. Less predictable than production declines from our proved reserves is the impact of constantly changing oil and natural gas prices on cash flows. We attempt to mitigate the price risk with our hedging program. Reserves and production volumes are influenced, in part, by the amount of future capital expenditures. In turn, capital expenditures are influenced by many factors including drilling results, oil and natural gas prices, industry conditions, prices, availability and cost of goods and services and the extent to which oil and natural gas properties are acquired. In 2009, our capital expenditures will also be impacted by our liquidity issues and the related Deficiency under our Revolving Facility, as well as the Amended Consent which imposes significant constraints on our capital expenditures.

        Our primary cash requirements are for exploration, development and acquisition of oil and natural gas properties, payment of preferred stock dividends, payment of derivative loss settlements and the repayment of principal and interest on outstanding debt (including the Deficiency under our Revolving Facility). We have historically attempted to fund our exploration and development activities primarily through internally generated cash flows and budget capital expenditures based largely on projected cash flows, however we do not anticipate that our cash flows will be sufficient to fund our primary cash requirements. We routinely adjust capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, and cash flow. We typically have funded acquisitions from borrowings under our credit facilities, cash flow from operations and sales of common stock and preferred stock, though we do not anticipate making any acquisitions in the foreseeable future.

        Significant changes to working capital affects our liquidity in the short term. As of December 31, 2008, our outstanding debt was classified as current due to the amendment in the maturity date to June 30, 2009 as provided by the Amended Consent which requires a $25 million payment due 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 (see "Revolving Facility" below for additional discussion). Our derivative instrument asset is indicative of potential future cash settlement inflows on our outstanding oil and natural gas derivative positions, which are scheduled to settle in future months. The fair market value represents the potential settlement for those contracts if the market prices remain unchanged. Should commodity prices increase or decrease, the fair value of those outstanding contracts would change, as evidenced in 2008 as the position flipped from a liability at year-end 2007 to an asset at year-end 2008. When our derivatives result in cash settlement outflows, we receive higher cash inflows on the sale of our physical production at those higher market prices, thus providing us with funds to cover at least a portion of any derivative payments that may come due in the future. This was not true, however, for the portion of our 2008 production that was overhedged. Approximately 115% of our natural gas production and approximately 190% of our anticipated crude oil production was hedged in 2008 as a result of a decrease in expected production since the time we entered into our 2008 derivative positions.

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        We have historically used our credit facilities to supplement any deficiencies between operating cash flow and capital expenditures. Our outstanding debt balance at March 16, 2009 was $234.0 million.

        During 2007, we realized increased cash flows as a result of our public and private stock offerings. We have also realized cash flows from the exercises of options and warrants to acquire shares of our common stock, although we typically do not rely on proceeds from the exercise of warrants and stock options to sustain our business, as the timing of their exercise is unpredictable. At December 31, 2008, 2007 and 2006, we had certain options outstanding and exercisable for shares of our common stock.

        We realized approximately $19.2 million related to the sale of a pipeline and approximately 120 properties in Texas and Mississippi to various buyers during 2008, and we used the proceeds to reduce outstanding debt and fund ongoing capital spending. In connection with our ongoing financial and strategic alternatives process, we are actively pursuing the possible sale of some or all of our assets or other business combination involving the Company.

        As a result of the strategic alternatives process we began in late 2007, we reduced our planned capital spending for 2008 as compared to recent years. During the first quarter of 2008, our Board of Directors approved a reduced capital budget. This program called for the drilling of 27 to 30 wells (10.4 to 10.7, net) during 2008, primarily in south Texas and, to a lesser extent, in southeast New Mexico, complemented by selected expenditures for land and seismic. The recent worldwide financial and credit crisis has reduced the availability of liquidity and credit worldwide, and the recent substantial declines in worldwide equity markets, including our stock prices, make it more difficult to effectively raise capital through equity issuances.

        We had cash and cash equivalents at December 31, 2008 of $8.5 million consisting primarily of short-term money market investments, as compared to $7.2 million at December 31, 2007. Working capital was a deficit of $203.3 million as of December 31, 2008, as compared to a surplus of $2.3 million at December 31, 2007. In 2008, we classified all of our outstanding debt as current due to the amendment in the maturity date to June 30, 2009 required by the Amended Consent.

        Net Cash Provided By Operating Activities —The decrease in cash flows provided by operating activities for year ended December 31, 2008 as compared to the same period in 2007 is primarily a result of cash settlement losses of approximately $18.1 million on our derivative contracts as compared to cash settlement gains of $3.6 million in 2007. Another contributor to the decrease in cash flows in 2008 was a decrease in production revenue and an increase in cash costs such as severance taxes, oil and natural gas operating expenses and G&A expenses, including strategic alternatives process costs and retention bonus payments. Changes in working capital increased total cash flows by $4.1 million in 2008 as compared to decreasing total cash flows by $2.0 million in 2007.

        The significant increase in cash flows provided by operating activities for the year ended December 31, 2007 compared to 2006 was primarily due to the January 2007 Acquisition. The major source of funds was revenue of $160.9 million, partially offset by cash operating expenses of $30.2 million and general and administrative expenses of $17.2 million. Contributing to the decrease in the level of cash provided by operating activities in 2007 was the net timing effects of receipts of accounts receivable payments of accrued liabilities and accounts payables.

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        Net cash generated from operating activities is a function of production and commodity prices, which are inherently volatile and unpredictable, and costs of operating our business and properties. In an effort to reduce the volatility realized on commodity prices, we enter into derivative instruments. Due to lower natural gas market pricing, we realized a benefit in cash settlement gains of $4.5 million and $4.7 million on our natural gas derivatives during 2007 and 2006, respectively. Partially offsetting these cash inflows were cash settlement losses of $0.9 million on our crude oil derivatives during 2007. Overall, oil and gas production revenue, including the effects of derivatives and hedging, for 2007 increased 24% over 2006.

        Fluctuations in commodity prices have been the primary reason for our short-term changes in cash flow from operating activities. 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. This was a factor in our 2008 results, which reflected a 24% lower proved reserve base at year-end. 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.

        Net Cash Used In Investing Activities —We have historically reinvested a substantial portion of our cash flows in our drilling, acquisition, land and geophysical activities. Under our reduced 2008 program, we spent approximately $47.4 million on our drilling and operating program. We drilled 27 gross wells in 2008, of which 25 gross wells were apparent successes. Leasehold, capitalized G&A and interest, and geological and geophysical activities accounted for expenditures of $12.7 million. There were also minimal capital expenditures associated with computer hardware, office equipment and other miscellaneous capital charges. This limited program compares to the prior year in which our largest expenditure was the acquisition that occurred in January 2007. During 2008, proceeds from the sale of certain non-core properties in Texas and Mississippi and a pipeline to various buyers totaled approximately $19.2 million. In 2009, we do not anticipate that our cash flows will be sufficient to fund our primary cash requirements and reinvestment of cash flows in our drilling, acquisition, land and geophysical activities will be severely limited.

        Due to the overhedged position in 2008, the cash settlements related to overhedged production are reflected in investing activities because they do not apply to operating revenue and are similar in nature to an investment. Approximately 45% of our oil settlements and approximately 20% of our natural gas settlements are represented by the $10.6 million of speculative overhedged derivative settlements in this section of the statement of cash flows. The remainder of cash settlements is located in net cash provided by operating activities. For further discussion of our overhedged position, see "Approach to the Business" above. This was not a factor in 2007 or 2006.

        We used $515.8 million in investing activities during 2007. Acquisition costs of $375.2 million were related to the January 2007 Acquisition, which was the largest in our history. Capital expenditures of $113.2 million were attributable to the drilling of 50 gross wells, 46 of which were apparently successful and 39 recompletions. Higher net capital costs per well in 2007 as compared to prior years were due to higher average working interests and higher gross costs per well in Arkansas and Deep Frio project areas as compared to wells drilled in previous years. General increases in costs of services as a result of a higher commodity price environment also contributed. Other spending included $20.5 million attributable to land holdings, capitalized G&A and interest and $6.0 million for seismic data and other geological and geophysical expenditures. The remaining capital expenditures were associated with computer hardware and office furniture and equipment. We also received $1.1 million during early 2007 from the sale of a portion of our interest in a Louisiana well.

        During the year ended December 31, 2006, we used $140.4 million in investing activities. Capital expenditures of $82.6 million were attributable to the drilling of 52 gross wells, 43 of which were apparently successful. Acquisition costs totaled $39.4 million, mainly related to the acquisition of

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additional interests in the Chapman Ranch Field late in 2006 and final adjustments to the purchase price of the 2005 acquisition of Cinco Energy Corporation. Other spending included $14.0 million attributable to land holdings, capitalized G&A and interest and $7.7 million for increased seismic data and other geological and geophysical expenditures. Drilling advances to the operator of our Queen City properties decreased in 2006 by approximately $2.9 million. We also received $0.6 million during 2006 from the sale of our Buckeye properties. The remaining capital expenditures were associated with computer hardware and office furniture and equipment.

        Net Cash Provided By (Used in) Financing Activities —During the year ended December 31, 2008, we repaid $21.0 million under our Revolving Facility using proceeds from our asset sales. We also paid quarterly dividends on our preferred stock in January, April, July and October 2008.

        Cash flows provided by financing activities were significantly impacted by the public offerings of common stock and preferred stock completed in January 2007. In connection with the newly issued preferred stock, we paid $5.9 million in dividends to preferred shareholders during 2007. We also refinanced our prior credit facility borrowings of $129 million with our current Revolving Facility, which we borrowed against to partially finance the January 2007 Acquisition. In total, we had $275.0 million in borrowings and $144.0 million in repayments during 2007. In connection with our Revolving Facility, we incurred loan costs of approximately $3.7 million. In addition, we received approximately $42,100 in proceeds from the issuance of common stock related to options exercised in 2007.

        During the year ended December 31, 2006, cash flows provided by financing activities totaled $44.4 million. We had $62.0 million in borrowings and $18.0 million in repayments under our prior credit facility. We incurred loan costs of approximately $0.2 million in amending our prior credit facility. In addition, we received $0.6 million in proceeds from the issuance of common stock related to options exercised in 2006.

Revolving Facility

        On January 30, 2007, we entered into the Revolving Facility with the Lenders, in favor of the Company and certain of its wholly-owned subsidiaries in an amount equal to $750 million. The Revolving Facility has a letter of credit sub-limit of $20 million. The Revolving Facility was scheduled to mature on January 31, 2011. At December 31, 2008, borrowings under the Revolving Facility bore interest at LIBOR plus an applicable margin ranging from 1.25% to 2.50% or Prime plus a margin of up to 0.50%, with an unused commitment fee ranging from 0.50% to 0.25%, all of which depend on the utilization percentage of the conforming borrowing base. At December 31, 2008, the interest rates applied to our outstanding Prime and LIBOR borrowings were 3.75% and 4.33%, respectively, and we had a rate of 0.25% applied to our unused borrowing capacity.

        As of December 31, 2008, $239 million in total borrowings were outstanding under the Revolving Facility. The borrowing base was reduced from $320 million to $300 million during the fourth quarter of 2007 and the conforming borrowing base was reduced from $300 million to $250 million. In early May 2008, our Revolving Facility's borrowing base and conforming borrowing base were redetermined by our banks and set at $250 million and $225 million, respectively. These reductions were primarily the result of declines in commodity prices, 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 our independent reserve engineers.

        On July 11, 2008, in connection with the proposed merger with Chaparral, we entered into a Consent. Agreement (the "Chaparral Consent"). Pursuant to the Chaparral Consent and subject to the terms thereof, the Lenders deferred their right to conduct a borrowing base redetermination on or before June 30, 2008 and agreed to conduct the redetermination on October 31, 2008. We paid the Lenders a fee of approximately $0.4 million in connection with the deferral of the redetermination. On November 5, 2008, the Lenders agreed to delay the interim redetermination from October 31, 2008

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until November 15, 2008. In consideration for this deferral, the Lenders placed a restriction upon the current borrowing base such that it was effectively lowered to $240 million until the interim redetermination occurred. Pursuant to the terms of the Revolving Facility, upon the completion of the redetermination, our borrowing base would also be the conforming borrowing base. This redetermination process was completed during January 2009 and 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 elected to prepay the Deficiency in six equal monthly installments, with the first $19 million installment being due on February 9, 2009. On February 9, 2009, we entered into 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 $19 million installment payments to be due on August 10, 2009. In connection with the February Consent, we agreed to prepay $5.0 million of our 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 the prepayments to be applied on a pro rata basis to reduce the remaining six $19 million deficiency payments. On March 10, 2009, we entered into 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 the Amended Consent which provides, among other things, (1) that we will 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 will be an event of default (i) if we fail 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 are in default under or our hedging arrangements have been terminated or cease to be effective without the prior written consent of our Lenders, (3) that our advances under the Revolving Facility will 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% as of March 16, 2009), (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. To comply with the terms of the Amended Consent, we anticipate that we will need to (i) sell select individual assets prior to May 31, 2009 to enable us to make the $25 million payment which is due on May 31, 2009, and/or (ii) negotiate a commitment letter with a new lender or group of lenders prior to May 15, 2009 in an amount sufficient to repay all of our obligations under the Revolving Facility on or before June 30, 2009, and/or (iii) have negotiated the sale, merger or other business combination involving us which results in the repayment of all of our obligations under the Revolving Facility prior to May 15, 2009 and to have closed such transaction on or before June 30, 2009. The Amended Consent limits the making of capital expenditures and we anticipate a severe curtailment of our drilling plans and other capital expenditures in 2009.

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        If we breach any of the provisions of the Amended Consent or the Revolving Facility, our Lenders will be entitled to declare an event of default, at which point the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, would become immediately due and payable. In any event, the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, will be payable on June 30, 2009 unless earlier paid or a further extension with respect to payment is negotiated with our Lenders. Our Lenders may take action to enforce their rights with respect to the outstanding obligations under the Revolving Facility. Because substantially all of our assets are pledged as collateral under the Revolving Facility, if our Lenders declare an event of default, they would be entitled to foreclose on and take possession of our assets. In such an event, we may be forced to liquidate or to otherwise seek protection under Chapter 11 of the U.S. Bankruptcy Code. These matters, as well as the other risk factors related to our liquidity and financial position raise substantial doubt as to our ability to continue as a going concern. With respect to our compliance with the Amended Consent, there can be no assurance that we will be able to further negotiate the terms of the Amended Consent or negotiate a further restructuring of the related indebtedness or that we will be able to make any required payments when they become due. Moreover, there can be no assurance that we will be successful in our efforts to comply with the terms of the Amended Consent, including our ongoing efforts to evaluate and assess our various financial and strategic alternatives (which may include the sale of some or all of our assets, a merger or other business combination involving the Company, or the restructuring or recapitalization of the Company). If such efforts are not successful, we may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code. See ITEM 1A. "RISK FACTORS —Our January 2009 borrowing base redetermination resulted in a $114 million borrowing base deficiency under our Revolving Facility and we may not be able to satisfy the terms and conditions of our Amended Consent relating thereto or to otherwise repay our borrowing base deficiency or satisfy our other liabilities."

        Our obligations under the Revolving Facility are secured by substantially all of our 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 common stock dividends and certain distributions of cash or properties and certain liens but no longer contains any financial covenants.

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

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Shelf Registration Statement & Offerings

        In the third quarter of 2007, the SEC declared effective our registration statement filed with the SEC that registered securities of up to $500 million of any combination of debt securities, preferred stock, common stock, warrants for debt securities or equity securities of the Company and guarantees of debt securities by our subsidiaries. Net proceeds, terms and pricing of the offering of securities issued under the shelf registration statement will be determined at the time of the offerings. The shelf registration statement does not provide assurance that we will or could sell any such securities. Our ability to utilize our shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us. However, because the aggregate market value of our outstanding common stock is less than $75 million, the type and amount of any securities offering under the registration statement may be limited.

Convertible Preferred Stock

        As noted above, we completed the public offering of 2,875,000 shares of our Convertible Preferred Stock in January 2007. We used the $138.4 million in net proceeds from this offering, along with the proceeds from the concurrent common stock offering of $138.1 million and borrowings under our Revolving Facility, to finance the January 2007 Acquisition and to refinance our prior credit facility.

        Dividends.     The Convertible Preferred Stock accumulates dividends at a rate of $2.875 for each share of Convertible Preferred Stock per year. Dividends are cumulative from the date of first issuance and, to the extent payment of dividends is not prohibited by our debt agreements, assets are legally available to pay dividends and our Board of Directors or an authorized committee of our Board declares a dividend payable, we will pay dividends in cash, every quarter. The first payment was made on April 15, 2007 and we continued to make quarterly dividends payments through October 15, 2008. The Board did not declare a dividend in the fourth quarter of 2008 due to our current lack of liquidity. Cumulative dividends in arrears at December 31, 2008 amounted to $1.7 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;

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•

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 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 January 2007 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.

        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 of conversion. The conversion price is subject to adjustment upon the occurrence of certain events. The conversion price on the conversion date and the number of shares of our common stock, as applicable, to be delivered upon conversion may be adjusted if certain events occur.

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

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

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        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.

        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 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:

•

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



•

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



•

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

Off Balance Sheet Arrangements

        The Company currently does not have any off balance sheet arrangements.

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Contractual Cash Obligations

        The following table summarizes our contractual cash obligations as of December 31, 2008 by payment due date:

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(1)

Excludes amounts for interest expense payable upon outstanding debt. Future interest obligations under our Revolving Facility are uncertain, due to the variable interest rate on fluctuating balances and the uncertainty as to the timing of principal repayments under the Amended Consent (see Note 11 to our consolidated financial statements). Based on a 6.03% weighted average interest rate on amounts outstanding under our Revolving Facility as of December 31, 2008, our cash payments for interest would be $14.4 million for 2009.

(2)

Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity.

(3)

This does not include our delivery commitment to Integrys Energy Services for 11.2 Bcf or $0.6 million as of December 31, 2008. Due to the fact that management expects to meet the minimum physical delivery commitment, we have not recorded a liability on our balance sheet as of December 31, 2008. For additional discussion of our delivery commitments, see Note 2 to our consolidated financial statements.

(4)

The table excludes quarterly dividends on our Convertible Preferred Stock. Dividends are cumulative and payable in arrears if not paid each quarter.

(5)

We did not have any capital leases or purchase obligations as of December 31, 2008.

(6)

We have not included our ARO liability here because historically the actual cash outlay is minimized significantly by the salvage value. In accordance with SFAS No. 143, we do not account for salvage value on our balance sheet.

FAIR VALUE MEASUREMENTS

        Effective January 1, 2008, we partially adopted SFAS No. 157, Fair Value Measurements, which provides a common definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements, but does not require any new fair value measurements. The partial adoption of SFAS No. 157 had no impact on our consolidated financial statements, but it did result in additional required disclosures as set forth in Note 10 to our consolidated financial statements. In February 2008, the FASB issued FSP 157-2, Effective Date of FASB Statement No. 157 , which delays the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the consolidated financial statements on a recurring basis (at least annually). Accordingly, we have not yet applied the provisions of SFAS No. 157 to our AROs.

        SFAS No. 157 defines fair value as the price that would be received to sell an asset or transfer a liability in an orderly transaction between market participants at the measurement date. Currently the only fair value measurements we utilize are related to our AROs and derivative instruments. While our

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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, over-the-counter quotes, volatility, historical correlations of pricing data and LIBOR and other liquid money market instrument rates. Our counterparties utilize internally developed basis curves that incorporate observable and unobservable market data. Although we believe these valuations are the best estimates of the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ from these estimates, and the differences could be material.

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

•

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



•

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



•

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 as Level 3 and expect to categorize our AROs' fair value measurements as Level 3 upon full adoption of SFAS No. 157. As interpretations of SFAS No. 157 evolve, our classification of certain instruments within the hierarchy may be revised. See "Critical Accounting Policies and Estimates—Derivative and Hedging Activities" above, "Risk Management Activities—Derivatives and Hedging" below and Note 9 to our consolidated financial statements for additional discussion of our derivative instruments.

        In conjunction with the adoption of SFAS No. 157, we also adopted SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115, effective January 1, 2008. SFAS No. 159 allows a company the option to value its financial assets and liabilities, on an instrument by instrument basis, at fair value, and include the change in fair value of such assets and liabilities in its results of operations. We did not elect to apply the provisions of SFAS No. 159 to any of our financial assets or liabilities. Accordingly, there was no impact to our consolidated financial statements resulting from the adoption of SFAS No. 159.

RISK MANAGEMENT ACTIVITIES—DERIVATIVES AND HEDGING

        Due to the volatility of oil and natural gas prices, from time to time, we may enter 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 to commodity price fluctuations. While the use of these arrangements may limit our ability to benefit from increases in the price of oil and natural gas, it is also intended to reduce our potential exposure to adverse price movements. 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 were, at the time of their execution, intended to be used for trading or speculative purposes, but a portion of these instruments was subsequently deemed as such because of the decrease in our 2008 production. The use of derivative

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instruments involves some credit risk, but generally we place our derivative transactions 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 its liquidity could be negatively impacted. On a quarterly basis, our management sets all of our price-risk management policies, including volumes, types of instruments and counterparties. These policies are implemented by management through the execution of trades by the Chief Financial Officer after consultation and concurrence by the President and Chairman of the Board. Our Board of Directors monitors the Company's price-risk management policies and trades on a monthly basis.

        All of these price-risk management transactions are considered derivative instruments and accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended). These derivative instruments are intended to hedge our price risk and may be considered hedges for economic purposes. There are two types of accounting treatments for derivatives, (i) mark-to-market accounting and (ii) cash flow hedge accounting. For a discussion of these accounting treatments, see Note 9 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 following table provides additional information regarding our various derivative transactions that were recorded at fair value on the balance sheet as of December 31, 2008.

        The following table details the fair value of our commodity-based derivative contracts by year of maturity and valuation methodology as of December 31, 2008.

TAX MATTERS

        At December 31, 2008, we had cumulative NOL carryforwards for federal and state income tax purposes of approximately $124.9 million and $21.4 million, respectively, without consideration of valuation allowances. The federal and state NOL carryforwards will expire in varying amounts between

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2009 and 2028. In addition to the deferred tax assets associated with NOLs, we have additional net deferred tax assets of approximately $65.0 million related to both federal and state tax positions. In recording deferred income tax assets, we consider whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. We consider the scheduled reversal of deferred income tax liabilities and projected future taxable income for this determination. We believe that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to the historical evidence, and in light of the current market situation and the uncertainty surrounding our Revolving Facility and related Amended Consent, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and therefore have established a full valuation allowance to reduce our net deferred tax asset to zero at 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 may be subject to limitations under Section 382 of the Internal Revenue Code of 1986, as amended ("Section 382") if we undergo a majority ownership change as defined by Section 382.

        We would undergo a majority ownership change if, among other things, the stockholders who own or have owned, directly or indirectly, five percent or more of our common stock or are otherwise treated as five percent stockholders under Section 382 and the regulations promulgated thereunder, increase their aggregate percentage ownership of our stock by more than 50 percentage points over the lowest percentage of stock owned by these stockholders at any time during the testing period, which is generally the three-year period preceding the potential ownership change. In the event of a majority ownership change, Section 382 imposes an annual limitation on the amount of taxable income a corporation may offset with the NOL carryforwards. Any unused annual limitation may be carried over to later years until the applicable expiration of the respective NOL carryforwards. The amount of the limitation may, under certain circumstances, be increased by built-in gains held by us at the time of the change that are recognized in the five-year period after the change. Any built in losses on assets held subsequent to a merger are subject to the limitation. If we were to undergo a majority ownership change, we will likely be required to record a reserve for some or all of the asset currently recorded on our balance sheet. 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 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.

        At December 31, 2008, under Section 382 rules, approximately $80.5 million of our total federal NOL carryforward of $124.9 million was subject to a potential annual limitation of $12 million. Of that $80.5 million, $22 million was subject to further annual limitations. The $22 million amount represents the following two separate limitations which occurred prior to 2008: (1) $17.4 million acquired in a December 2003 merger, which is subject to an annual limitation of approximately $1 million per year

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and (2) $5.4 million acquired in a November 2005 acquisition, which is subject to an annual limitation of approximately $2 million per year.

        FASB Interpretation No. 48 ("FIN 48"), Accounting for Uncertainty in Income Taxes , provides guidance on recognition and measurement of uncertainties in income taxes. FIN 48 requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. See Notes 2 and 17 to our consolidated financial statements. Upon adoption of FIN 48 on January 1, 2007, we recognized a liability of approximately $0.5 million, which was a reduction in the January 1, 2007 retained earnings balance. During second quarter 2008, we recorded an income tax benefit of approximately $0.4 million as a result of the conclusion of a state audit where no prior benefit was taken for an uncertain tax position, which is now effectively settled without adjustment by the state tax authorities.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

        In December 2007, the FASB issued SFAS No. 141R, Business Combinations ("SFAS No. 141R"). SFAS No. 141R expands the definition of transactions and events that qualify as business combinations; requires that the acquired assets and liabilities, including contingencies, be recorded at the fair value determined on the acquisition date and changes thereafter reflected in earnings, not goodwill; changes the recognition timing for restructuring costs; and requires acquisition costs to be expensed as incurred. Adoption of SFAS No. 141R is required prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Early adoption and retroactive application of SFAS No. 141R to fiscal years preceding the effective date are not permitted. However, accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for prior business combinations will impact tax expense instead of impacting the prior business combination accounting starting January 1, 2009. We are currently evaluating the changes provided in SFAS No. 141R and believe it could have a material impact on our consolidated financial statements if we were to undertake a significant acquisition or business combination.

        In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interest in Consolidated Financial Statements ("SFAS No. 160"). SFAS No. 160 re-characterizes minority interests in consolidated subsidiaries as non-controlling interests and requires the classification of minority interests as a component of equity. Under SFAS No. 160, a change in control will be measured at fair value, with any gain or loss recognized in earnings. The effective date for SFAS No. 160 is for annual periods beginning on or after December 15, 2008. Early adoption and retroactive application of SFAS No. 160 to fiscal years preceding the effective date are not permitted. We currently do not expect adoption of this statement to have an impact on our consolidated financial statements.

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        In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133 ("SFAS No. 161"). SFAS No. 161 requires entities to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. SFAS No. 161 is effective for annual periods beginning on or after November 15, 2008. Early application of SFAS No. 161 is encouraged, as are comparative disclosures for earlier periods at initial adoption. We will adopt SFAS No. 161 on January 1, 2009 and do not expect adoption of this statement to impact our consolidated financial statements, but we do expect it to impact disclosures made in our future quarterly and annual filings.

        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.

ITEM 7A.    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 year-end December 31, 2008 outstanding borrowings and interest rates of 3.75% and 4.33% applied to various borrowings, a 10% change in these interest rates would result in an increase or decrease in interest expense of approximately $1.0 million on an annual basis.

        The debt and equity markets have recently exhibited adverse conditions. The unprecedented volatility and upheaval in the capital markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets. We believe the recent events in the global markets had significant impact on our recent borrowing base redetermination that resulted in a $114 million borrowing base deficiency. The continued credit crisis and related turmoil in the global financial system and economic recession in the U.S. create financial challenges if conditions do not improve and will affect our ability to access credit markets. We will continue to monitor our liquidity and the capital markets as we continue to assess our financial and strategic alternatives.

        As of December 31, 2008, our outstanding debt was classified as current due to the amendment in the maturity date to June 30, 2009 as provided by the Amended Consent which requires a $25 million payment due 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.

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        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. 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 early 2007, we put in place several natural gas and crude oil derivatives to hedge our expected 2008 and 2009 production to achieve a more predictable cash flow. As a result of changes to our forecasted 2008 production and the impact of certain asset divestitures, both of which reduced production as compared to that expected at the time we entered into the derivative contracts, we had approximately 115% and 190% of our 2008 natural gas and crude oil production, respectively, covered by derivative contracts. This overhedged position exposed us to greater risk of commodity price increases because we did not have the physical production cash inflows to offset the losses incurred on the portion of the contracts that were overhedged. Please refer to Note 9 to our consolidated financial statements for a discussion of these contracts. The following is a list of contracts outstanding at December 31, 2008:

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(1)

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

(2)

Our crude oil contracts were 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 these contracts and the change in fair value is reflected in total revenue.

        At December 31, 2008, the fair value of the outstanding contracts was a net asset of approximately $15.4 million. See ITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS— RISK MANAGEMENT ACTIVITIES—DERIVATIVES AND HEDGING". A 10% change in the commodity price per unit, as long as the price is either above the ceiling or below the floor price of each contract, would cause the fair value total of the hedge to increase or decrease by approximately $1.5 million.

        All of our business is conducted in the United States with transactions denominated in U.S. dollars and, as a result, we do not have material exposure to currency exchange rate risks

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

        See the Consolidated Financial Statements and Supplementary Information listed in the accompanying Index to Consolidated Financial Statements and Supplementary Information on page F-1 herein.

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ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

        None.

ITEM 9A.    CONTROLS AND PROCEDURES

        (a) Disclosure Controls and Procedures.     We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission ("SEC") under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms, and that information is accumulated and communicated to our management, including our Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), as appropriate to allow timely decisions regarding required disclosure.

        In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our CEO and CFO, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. As described below under Management's Annual Report on Internal Control over Financial Reporting, our CEO and CFO have concluded that, as of the end of the period covered by this Annual Report on Form 10-K, the Company's disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms.

        (b) Management's Annual Report on Internal Control over Financial Reporting.     Management, including the CEO and CFO, has the responsibility for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) of the Exchange Act. Internal control over financial reporting is a process designed by, or under the supervision of, the Company's principal executive and principal financial officers, or persons performing similar functions and influenced by the Company's Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America ("GAAP"). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate or insufficient because of changes in operating conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        A control deficiency exists when the design or operation of a control does not allow management or employees, in the ordinary course of performing their assigned functions, to prevent or detect misstatements on a timely basis. A significant deficiency is a control deficiency, or combination of control deficiencies, that adversely affects the Company's ability to initiate, authorize, record, process, or report external financial data reliably in accordance with GAAP, such that there is a more than remote likelihood that a misstatement of the Company's annual or interim financial statements that is more than inconsequential will not be prevented or detected. A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

        Management assessed internal control over financial reporting of the Company and subsidiaries as of December 31, 2008. The Company's management conducted its assessment in accordance with the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the

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Treadway Commission ("COSO"). Management has concluded that the internal control over financial reporting was effective as of December 31, 2008.

        BDO Seidman, LLP, the independent registered public accounting firm who also audited the Company's consolidated financial statements, has issued its own attestation report on the effectiveness of internal controls over our financial reporting as of December 31, 2008, which is filed herewith.

        (c) Changes in Internal Control Over Financial Reporting.     There have not been any changes in the Company's internal control over financial reporting during the fiscal quarter ended December 31, 2008 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

        (d) Report of Independent Registered Public Accounting Firm     

Board of Directors and Stockholders
Edge Petroleum Corporation
Houston, Texas

        We have audited Edge Petroleum Corporation's internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying "Item 9A, Management's Report on Internal Control Over Financial Reporting". Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        In our opinion, Edge Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.

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        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Edge Petroleum Corporation as of December 31, 2008 and 2007 and the related consolidated statements of operations, comprehensive income (loss), stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2008, and our report dated March 16, 2009 included an explanatory paragraph that expressed substantial doubt about the Company's ability to continue as a going concern.

/S/ BDO SEIDMAN, LLP
BDO Seidman, LLP
Houston, Texas
March 16, 2009

ITEM 9B.    OTHER INFORMATION

        None.

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PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

        The information regarding directors and executive officers required under ITEM 10 will be contained within the definitive Proxy Statement for the Company's 2009 Annual Meeting of Shareholders (the "Proxy Statement") under the headings "Election of Directors," "Meetings and Committees of the Board" and "Compliance with Section 16(a) of the Exchange Act" and is incorporated herein by reference. The Proxy Statement will be filed pursuant to Regulation 14A with the Securities and Exchange Commission not later than 120 days after December 31, 2008, or the Company will file an amendment to this Form 10-K within the same time period that includes the required information. Pursuant to Item 401(b) of Regulation S-K certain of the information required by this item with respect to our executive officers is set forth in Part I of this report.

        We have adopted a code of ethics for all employees, officers and directors. That code is available on our website at www.edgepet.com . Any waivers of, or amendments to, the Code of Ethics will be posted on the website.

ITEM 11.    EXECUTIVE COMPENSATION

        The information required by ITEM 11 will be contained in the Proxy Statement under the headings "Executive Compensation," "Compensation Committee Interlocks and Insider Participation," "Compensation Committee Report" and "2008 Director Compensation" and is incorporated herein by reference.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

        The information required by ITEM 12 will be contained in the Proxy Statement under the headings "Security Ownership of Certain Beneficial Owners and Management" and "Equity Compensation Plan Information" and is incorporated herein by reference.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

        The information required by ITEM 13 will be contained in the Proxy Statement under the heading "Transactions with Related Persons" and is incorporated herein by reference.

ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES

        The information required by ITEM 14 will be contained in the Proxy Statement under the heading "Approval of Appointment of Independent Public Accountants" and is incorporated herein by reference.

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PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)

Financial Statements and Schedules:

1.

Financial Statements:    See Index to the Consolidated Financial Statements and Supplementary Information immediately following the signature page of this report.

2.

Financial Statement Schedule:    See Index to the Consolidated Financial Statements and Supplementary Information immediately following the signature page of this report.

(b)

Exhibits: The following documents are filed as exhibits to this report:

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*

Filed herewith.

†

Denotes management or compensatory contract, arrangement or agreement, or a summary or description thereof.

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SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

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EDGE PETROLEUM CORPORATION

Index to Consolidated Financial Statements and Supplementary Information

CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

        All schedules are omitted, as the required information is either inapplicable or the information is presented in the Consolidated Financial Statements or related notes.

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Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Edge Petroleum Corporation
Houston, Texas

        We have audited the accompanying consolidated balance sheets of Edge Petroleum Corporation (the "Company") as of December 31, 2008 and 2007 and the related consolidated statements of operations, comprehensive income (loss), stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Edge Petroleum Corporation at December 31, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

        As discussed in Note 2 to the consolidated financial statements, effective January 1, 2007, the Company adopted the provisions of Financial Accounting Standards Board Interpretation No. 48, "Accounting for Uncertainty in Income Taxes."

        The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, at December 31, 2008, as a result of a deficiency in its revolving credit agreement subsequent to year end, the Company is in a negative working capital position with significant payments due June 30, 2009 under the revolving credit agreement. This condition gives rise to substantial doubt about the Company's ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) Edge Petroleum Corporation's internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 16, 2009 expressed an unqualified opinion thereon.

/s/ BDO SEIDMAN, LLP BDO Seidman, LLP Houston, Texas March 16, 2009

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EDGE PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

See accompanying notes to the consolidated financial statements.

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EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

See accompanying notes to the consolidated financial statements.

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EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

See accompanying notes to the consolidated financial statements.

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EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying notes to the consolidated financial statements.

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EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

See accompanying notes to the consolidated financial statements.

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION, NATURE OF OPERATIONS AND GOING CONCERN UNCERTAINTY

        General —Edge Petroleum Corporation(the "Company") was organized as a Delaware corporation in August 1996 in connection with its initial public offering and the related combination of certain entities that held interests in Edge Joint Venture II (the "Joint Venture") and certain other oil and natural gas properties; herein referred to as the "Combination". In a series of transactions the Company issued an aggregate of 4.7 million shares of common stock and received in exchange 100% of the ownership interests in the Joint Venture and certain other oil and natural gas properties. In March 1997, and contemporaneously with the Combination, the Company completed the initial public offering of 2.8 million shares of its common stock (the "Offering"). In December 2003, the Company completed a merger with Miller Exploration Company ("Miller") in a stock for stock transaction, in which the Company issued 2.6 million shares of common stock to the shareholders of Miller. In December 2004 and January 2005, the Company completed a public offering of common stock in which 4.0 million shares were issued in order to fund a significant asset acquisition. In November 2005, the Company acquired 100% of the stock of Cinco Energy Corporation ("Cinco"), which continues as a wholly owned subsidiary named Edge Petroleum Production Company. In January 2007, the Company completed two concurrent public offerings in which approximately 2.9 million shares of preferred stock and approximately 10.9 million shares of common stock were issued in order to partially fund a January 2007 asset acquisition.

        Nature of Operations —The Company is 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. The Company's resources and assets are managed and its results are reported as one operating segment. The Company conducts its operations primarily along the onshore United States Gulf Coast, with an emphasis in Texas, Mississippi, New Mexico, and Louisiana. In its exploration efforts the Company emphasizes an integrated geologic interpretation method incorporating 3-D seismic technology and advanced visualization and data analysis techniques utilizing state-of-the-art computer hardware and software.

        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. On February 7, 2008, the Company provided an update on the strategic alternative process and publicly announced that it would implement a process to explore a merger or sale of the Company. As a result of the strategic alternatives process, on July 15, 2008, the Company and Chaparral Energy, Inc. ("Chaparral"), a privately held company, announced that they had entered into a definitive merger agreement that provided for Chaparral to acquire Edge in an all-stock transaction. To provide additional funding for the transaction, Chaparral expected to sell 1.5 million shares of its Series B convertible preferred stock, par value $0.01 per share for $150 million in a private sale to Magnetar Financial LLC, on behalf of itself and one or more of its affiliates and assigns (collectively, "Magnetar").

        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. 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

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. ORGANIZATION, NATURE OF OPERATIONS AND GOING CONCERN UNCERTAINTY (Continued)

combined company, particularly in light of the challenging environment in the financial markets and the energy industry. As a result, after consultation with its legal and financial advisors, the Company's Board of Directors approved a merger termination agreement with Chaparral and a termination and settlement agreement among Edge, Chaparral and Magnetar. Pursuant to the termination agreements, Magnetar reimbursed Chaparral $5.0 million for certain expenses, of which $1.5 million was paid to the Company at Chaparral's direction, of which the Company paid $0.3 million to its then-financial advisor, Merrill Lynch.

        Going Concern —In addition to the Deficiency under our Revolving Facility (defined in Note 11) created by the recent borrowing base redetermination (see discussion in Notes 11 and 12), the capital expenditures required to maintain and/or grow production and reserves are substantial. The Company's stock price has significantly declined over the past year which makes it more difficult to obtain equity financing on acceptable terms to address our liquidity issues. In addition, the Company is reporting negative working capital at December 31, 2008 and a third consecutive year of net losses for the year ended December 31, 2008, which is largely the result of impairments of the Company's oil and natural gas properties. Therefore, there is substantial doubt as to the Company's ability to continue as a going concern for a period longer than the current fiscal year. The Company's ability to continue as a going concern is dependent upon the success of its financial and strategic alternatives process, which may include the sale of some or all of our assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company. Until the possible completion of the financial and strategic alternatives process, the Company's future remains uncertain and there can be no assurance that its efforts in this regard will be successful.

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

        Principles of Consolidation —The consolidated financial statements include the accounts of all majority owned subsidiaries of the Company, including Edge Petroleum Operating Company Inc., Edge Petroleum Exploration Company, Edge Petroleum Production Company (formerly Cinco Energy Corporation), Miller Oil Corporation, and Miller Exploration Company, which are 100% owned subsidiaries of the Company. All intercompany balances and transactions have been eliminated in consolidation.

        Cash and Cash Equivalents —The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents.

        Financial Instruments —The Company's financial instruments consist of cash, receivables, payables, long-term 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. The carrying

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

amount of long-term debt as of December 31, 2008 and 2007 approximates fair value because the interest rates are variable and reflective of market rates. Derivative instruments are reflected at fair value based on quotes obtained from the Company's counterparties.

        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 December 31, 2008 and 2007, the Company's gas production was materially in balance, i.e. its cumulative portion of gas production taken and sold from wells in which the Company has an interest was not materially different from the Company's entitled interest in gas production from those wells.

        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 $63,800 of this commitment through December 31, 2008. In addition to the pipeline, Frontier also built and installed lateral gathering lines to eight locations. The remaining commitment on these laterals is $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. Although the Company believes there is the potential to develop this area and increase production, it does not currently have sufficient liquidity to ensure that this occurs in the timeframe required by the gas gathering and compression services agreement with Frontier.

        During 2008, the Company executed a gas gathering and compression services agreement with Integrys Energy Services ("Integrys") related to the construction and installation of a pipeline connecting the Company's Slick State properties to its Bloomberg properties in order to secure more advantageous plant processing, transportation and gathering fees and access to gas markets. The pipeline system was installed, operational and ready to redirect the production in September 2008. The contract minimum commitment to Integrys is approximately 11.2 Bcf over a three year period for the pipeline interconnect. The amount of total commitment is $550,000 plus 8% interest per annum, for a total liability of approximately $0.6 million. The Company has delivered approximately $71,400 of this commitment through December 31, 2008. The Company has not recorded a liability for this

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

commitment as it expects to meet the minimum physical delivery based on estimated anticipated production.

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

        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. Many of the Company's receivables are from joint interest owners on properties of which the Company is the operator. Thus, the Company may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company's crude oil and natural gas receivables are collected within two to three months. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated (see Note 3).

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

        Other Property, Plant & Equipment —Depreciation of other office furniture and equipment and computer hardware and software is provided using the straight-line method based on estimated useful lives ranging from one to seven years.

        Oil and Natural Gas Properties —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: (1) the successful-efforts method and (2) 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. The Company utilizes the full-cost method of accounting for oil and natural gas properties. 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. The Company's oil and natural gas properties are located within the United States of America, which constitutes one cost center. The Company capitalized $4.1 million, $4.0 million, and $3.0 million of general and administrative costs in 2008, 2007 and 2006, respectively. The Company also capitalizes a portion of interest expense on borrowed funds related to unproved oil and gas properties. The Company capitalized approximately $2.6 million, $7.9 million, and $5.3 million of interest costs in 2008, 2007 and 2006, respectively.

        In the measurement of impairment of proved oil and natural gas properties, the successful-efforts method of accounting follows the guidance provided in SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets , where the first measurement for impairment is to compare the net book value of the related asset to its undiscounted future cash flows using commodity prices consistent with management expectations. The full-cost method follows guidance provided in Securities and Exchange Commission ("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

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

depletion, depreciation and amortization, prior impairments and related tax effects) exceed the present value (using 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. In accordance with SEC Staff Accounting Bulletin ("SAB") No. 103, Update of Codification of Staff Accounting Bulletins , derivative instruments qualifying as cash flow hedges are to be included in the computation of limitation on capitalized costs. The Company has applied the mark-to-market accounting method of accounting since January 1, 2006; therefore, the ceiling tests at December 31, 2008, 2007 and 2006 were not impacted by the fair value of our derivatives.

        Impairment of oil and natural gas properties is assessed quarterly in conjunction with the Company's quarterly and annual SEC filings. The Company recorded a non-cash ceiling test impairment of oil and natural gas properties of $129.5 million ($84.2 million, net of tax) and $233.3 million ($215.8 million, net of tax) during the quarters ended September 30 and December 31, 2008, respectively, as a result of declines in commodity prices and negative revisions in the Company's proved reserve quantities. For the third and fourth quarters of 2007, the Company elected to use a pricing date subsequent to the balance sheet date, as allowed by SEC guidelines, to calculate the full-cost ceiling. As a result, no ceiling test impairment was required at September 30 or December 31, 2007. Subsequent pricing did not, however, eliminate the ceiling test impairments calculated at September 30 and December 31, 2008. The Company recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2006 of $96.9 million ($63.0 million, net of tax), during the third quarter of 2006, as a result of a decline in natural gas prices at the measurement date.

        Oil and natural gas properties are amortized using the unit-of-production method using estimates of proved reserve quantities. Investments in unproved properties are not amortized until proved reserves associated with the prospects can be determined or until impairment occurs. Unproved oil and natural gas properties consist of the cost of unevaluated leaseholds, cost of seismic data, exploratory and developmental wells in progress, and secondary recovery projects before the assignment of proved reserves. Oil and natural gas properties include costs of $16.4 million and $34.9 million at December 31, 2008 and 2007, respectively, related to unproved property, which were excluded from capitalized costs being amortized. Unproved properties are evaluated quarterly, and as needed, for impairment on a property-by-property basis. Factors considered by management in its impairment assessment include drilling results by the Company and other operators, the terms of oil and natural gas leases not held by production, production response to secondary recovery activities and available funds for exploration and development. If the results of an assessment indicate that an unproved property is impaired, the amount of impairment is added to the proved oil and natural gas property costs to be amortized. In accordance with SAB No. 106, Interaction of Statement 143 and the Full Cost Rules, the amortizable base used to calculate unit-of-production depletion includes estimated future development and dismantlement costs, and restoration and abandonment costs, net of estimated salvage values. The depletion rates per Mcfe for the years ended December 31, 2008, 2007 and 2006 were $5.08, $3.77, and $3.51, 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.

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        Asset Retirement Obligations —The Company accounts for asset retirement obligations under the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations, which provides for an asset and liability approach to accounting for Asset Retirement Obligations ("ARO"). Under this method, when legal obligations for dismantlement and abandonment costs, excluding salvage values, are incurred, a liability is recorded at fair value and the carrying amount of the related oil and gas properties is increased. Accretion of the liability is recognized each period using the interest method of allocation and the capitalized cost is depleted over the useful life of the related asset (see Note 7).

        Income Taxes —The Company accounts for income taxes under the provisions of SFAS No. 109, Accounting for Income Taxes , which provides for an asset and liability approach to accounting for income taxes. Effective January 1, 2007, the Company also applied the provisions of Financial Accounting Standards Board ("FASB") Interpretation No. 48, Accounting for Uncertainty in Income Taxes (an interpretation of FASB Statement No. 109) ("FIN 48"), and FASB Staff Position No. FIN 48-1, Definition of Settlement in FASB Interpretation No. 48 ("FSP FIN 48-1"). FIN 48 clarified the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on de-recognitions, classification, interest and penalties, accounting in interim periods, disclosure and transition. FSP FIN 48-1 provides that a company's tax position will be considered settled if the taxing authority has completed its examination, the company does not plan to appeal, and it is remote that the taxing authority would reexamine the tax position in the future (see Note 17).

        Earning per Share —The Company accounts for earnings per share in accordance with SFAS No. 128, Earnings per Share , which establishes the presentation requirements for earnings per share ("EPS") (see Note 19).

        Share-Based Compensation —At December 31, 2008, the Company had a share-based employee compensation plan that included restricted stock units and stock options issued to employees and non-employee directors, as more fully described in Note 19. Stock options were last issued in April 2004. The Company accounts for share-based compensation in accordance with the provisions of SFAS No. 123(R), Share-Based Payment, which requires that the compensation cost relating to share-based payment transactions be recognized in financial statements. The Company elected to use the modified-prospective method for adoption of SFAS No. 123(R) and recognized additional compensation expense of $68,937 in 2006. No further expense associated with stock options was recorded in 2007 or 2008 or is expected to be recognized unless future awards are granted. The Company has recorded compensation expense associated with the issuance of restricted stock and restricted stock units since the plan was adopted in 1997 and stock or stock units were first granted.

        Share-based compensation for the years ended December 31, 2008, 2007 and 2006 was approximately $1.6 million, $3.0 million and $2.0 million, respectively, of which $1.2 million, $2.4 million and $1.6 million, respectively, is included in general and administrative expenses ("G&A") and $0.4 million, $0.6 million and $0.4 million, respectively is capitalized to oil and natural gas properties.

        During the year ended December 31, 2008, 1,600 restricted stock units ("RSUs") were granted. At December 31, 2008, there were 305,020 RSUs outstanding, all of which are classified as equity instruments. No options were granted during the year ended December 31, 2008. During 2008, no

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

options were exercised or forfeited, resulting in 643,600 vested unexercised options outstanding at period end.

        Fair Value Measurements —Effective January 1, 2008, the Company partially adopted SFAS No. 157, Fair Value Measurements, which provides a common definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements, but does not require any new fair value measurements. The partial adoption of SFAS No. 157 had no impact on the Company's consolidated financial statements, but it did result in additional required disclosures as set forth in Note 10. In February 2008, the FASB issued FSP 157-2, Effective Date of FASB Statement No. 157 , which delays the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Accordingly, the Company has not yet applied the provisions of SFAS No. 157 to its AROs.

        In conjunction with the adoption of SFAS No. 157, the Company also adopted SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115, effective January 1, 2008. SFAS No. 159 allows a company the option to value its financial assets and liabilities, on an instrument by instrument basis, at fair value, and include the change in fair value of such assets and liabilities in its results of operations. The Company did not apply the provisions of SFAS No. 159 to any of its financial assets or liabilities. Accordingly, there was no impact to the Company's consolidated financial statements resulting from the adoption of SFAS No. 159.

        Derivatives and Hedging Activities —The Company accounts for its derivative contracts under the provisions of SFAS No. 133 (as amended). The statement requires that all derivatives be recognized as either assets or liabilities and measured at fair value, and changes in the fair value of derivatives be reported in current earnings, unless the derivative qualifies for cash flow hedge accounting treatment. If the derivative is designated as a cash flow hedge and the intended use of the derivative is to hedge the exposure to variability in expected future cash flows, then the changes in the fair value of the derivative instrument will generally be reported in Other Comprehensive Income ("OCI"). These gains and losses on the derivative instrument that are reported in OCI will be reclassified to earnings in the period in which earnings are impacted by the hedged item. If cash flow hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value and gains and losses that were accumulated in OCI will be recognized in earnings immediately. During the first quarter of 2006, the Company began applying mark-to-market accounting treatment to all outstanding derivative contracts. Therefore, the changes in fair value are not deferred through OCI, but rather recorded in revenue immediately as unrealized gains or losses (see Note 9).

        Comprehensive Income —The Company follows the provisions of SFAS No. 130, Reporting Comprehensive Income . SFAS No. 130 establishes standards for reporting and presentation of comprehensive income and its components. SFAS No. 130 requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements. In accordance with the provisions of SFAS No. 130, the Company has presented the components of comprehensive income on the face of the consolidated statements of comprehensive income (loss).

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        Use of Estimates —The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates.

        Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of undeveloped properties, future income taxes and related assets/liabilities, bad debts, derivatives, contingencies and litigation. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the ceiling test, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

        Concentration of Credit Risk —Substantially all of the Company's accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, the Company has not experienced significant credit losses on such receivables; however, in 2001, the Company reserved $0.5 million related to non-payments from two purchasers of the Company's oil and natural gas, of which $0.3 million was written off and $0.2 million was recovered during 2007. In 2008, the Company expensed approximately $0.1 million in accounts receivable from joint interest owners. In 2007, the Company expensed $0.5 million in accounts receivable, trade related to the ongoing Golden Prairie dispute that the Company no longer felt it could collect as it had exhausted its efforts on this matter. In 2006, the Company wrote off $1,571 in accounts receivable from joint interest owners. The Company cannot ensure that similar such losses may not be realized in the future.

        Recently Issued Accounting Pronouncements —In December 2007, the FASB issued SFAS No. 141R, Business Combinations ("SFAS No. 141R"). SFAS No. 141R expands the definition of transactions and events that qualify as business combinations; requires that the acquired assets and liabilities, including contingencies, be recorded at the fair value determined on the acquisition date and changes thereafter reflected in earnings, not goodwill; changes the recognition timing for restructuring costs; and requires acquisition costs to be expensed as incurred. Adoption of SFAS No. 141R is required prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Early adoption and retroactive application of SFAS No. 141R to fiscal years preceding the effective date are not permitted. However, accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for prior business combinations will impact income tax expense instead of impacting the prior business combination accounting starting January 1, 2009. The Company is currently evaluating the changes provided in SFAS No. 141R and believes it could have a material impact on the Company's consolidated financial statements if it were to undertake a significant acquisition or business combination.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interest in Consolidated Financial Statements ("SFAS No. 160"). SFAS No. 160 re-characterizes minority interests in consolidated subsidiaries as non-controlling interests and requires the classification of minority interests as a component of equity. Under SFAS No. 160, a change in control will be measured at fair value, with any gain or loss recognized in earnings. The effective date for SFAS No. 160 is for annual periods beginning on or after December 15, 2008. Early adoption and retroactive application of SFAS No. 160 to fiscal years preceding the effective date are not permitted. The Company currently does not expect adoption of this statement to have an impact on its consolidated financial statements.

        In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133 ("SFAS No. 161"). SFAS No. 161 requires entities to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. SFAS No. 161 is effective for annual periods beginning on or after November 15, 2008. Early application of SFAS No. 161 is encouraged, as are comparative disclosures for earlier periods at initial adoption. The Company will adopt SFAS No. 161 on January 1, 2009 and does not expect adoption of this statement to impact its consolidated financial statements, but it does expect it to impact disclosures made in its future quarterly and annual filings.

        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.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

        Below are the components of Accounts Receivable, Joint Interest Owners and Other, as of December 31, 2008 and 2007:

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(1)

Other receivables represent various miscellaneous refunds or credits that the Company is due that may not relate to Joint Interest Billings or Trade Receivables.

        The following table sets forth changes in the Company's allowance for doubtful accounts receivable, trade and joint interest owners and other, for the years ended December 31, 2008, 2007 and 2006:

4. OTHER CURRENT ASSETS

        Below are the components of other current assets as of December 31, 2008 and 2007:

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(1)

Consists of tubular goods and production equipment for wells and facilities.

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5. PROPERTY AND EQUIPMENT

        At December 31, 2008 and 2007, property and equipment consisted of the following:

        Costs associated with unproved properties and major development projects related to continuing operations of $16.4 million and $34.9 million as of December 31, 2008 and 2007, respectively, are excluded from amounts subject to amortization.

        The majority of the evaluation activities are expected to be completed within two to three years, subject to the Company's ability to obtain financing to increase its severely limited capital budget (see Note 11). These excluded costs represent unproved properties and major development projects in which the Company owns a direct interest, including the following:

•

Mississippi Salt Basin—The Company is conducting a large development project in the Mississippi Interior Salt Basin. The Company has contracted a company specializing in processing seismic data in salt provinces to reprocess one of the Company's merged proprietary seismic surveys. The new seismic processing continues the Company's efforts to integrate well control with the seismic data in order to define the salt-sediment interface on salt domes within the basin. The Company has continued to acquire new leasehold in 2008 and expects to renew certain of its existing leasehold for the Upper and Lower Hosston objectives in 2009. Costs excluded from the amortizable base associated with this play totaled approximately $10 million at December 31, 2008.



•

El Sauz—The El Sauz Project is an active 3-D seismic exploration project. The Company has been actively permitting, acquiring seismic options and new term leases for the planned 120 square mile proprietary 3-D seismic survey over the last year. Contractors are currently completing line clearing and surveying with data acquisition to begin in March 2009. The current timeline is to have the new 3-D seismic data ready for interpretation in the Company's office by

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. PROPERTY AND EQUIPMENT (Continued)

the end of the third quarter of 2009. Costs excluded from the amortizable base associated with this play totaled approximately $4 million at December 31, 2008.

•

Deep Frio Trend, south Texas—The Company's interest in the Frio trend increased as a result of the Chapman Ranch Field Acquisition in late 2006 (see Note 6). The Company completed the acquisition of a proprietary 3-D seismic survey in early 2007 over the Chapman Ranch field. The new 3-D seismic identified a number of development, exploitation and exploration opportunities. The Company anticipates drilling approximately 3 to 7 gross wells in the future to continue to develop this area. Costs excluded from the amortizable base associated with this play totaled approximately $1 million at December 31, 2008.

6. ACQUISITIONS AND DIVESTITURES

        South and southeast Texas asset acquisition in January 2007 —On November 16, 2006, the Company entered into two separate purchase and sale agreements (both of which were subsequently amended) with an unrelated privately held company for ownership interests in certain leasehold acreage, oil and natural gas properties located in southeast and south Texas, consisting of producing wells from the private company and eight other owners who transferred their interests to the private company prior to the closing, option and leasehold rights and exploration and development rights in an exploration project area known as the Mission project area in south Texas, and certain gathering facilities and ownership of approximately 13 miles of natural gas gathering pipelines and related infrastructure serving certain producing assets in southeast Texas (the "January 2007 Acquisition"). In addition, as part of this acquisition, the Company acquired a working interest, option and leasehold rights in two exploration ventures in separate areas, primarily in Texas, from the private company for $10.0 million. Closing occurred on January 31, 2007, accordingly, the Company's consolidated results of operations include the acquired properties in south and southeast Texas beginning February 1, 2007. On December 12, 2007 the Company accepted the final adjusted closing price of $384.4 million, which was adjusted pursuant to the post-closing adjustment provisions of the amended purchase and sale agreements. The Company financed the purchase price of the January 2007 Acquisition through public offerings of common and preferred stock (see Notes 13 and 14) and borrowings under its Revolving Facility (see Note 11). The Company also capitalized approximately $1.4 million in other direct costs resulting from the acquisition and assumed ARO liabilities of $0.9 million.

        During the third quarter 2007, the Company elected to terminate one of the two ventures in south Texas, which was entered into in January 2007. The effective date of termination for this venture was October 2, 2007. In exchange for returning all 3-D seismic data covering the area of mutual interest, the privately held company refunded the Company's payments since January 2007 related to this exploration venture. In October 2007, the Company received $5.5 million, including the $5.0 million initial price paid for the venture and $0.5 million in expenses related to the venture, which were incurred and paid to the privately held company from January to September 2007.

        The following unaudited pro forma results for the year ended December 31, 2007 show the effect on the Company's consolidated results of operations as if the January 2007 Acquisition had occurred on January 1, 2007. The following unaudited pro forma results for the year ended December 31, 2006 show the effect on the Company's consolidated results of operations as if the January 2007 Acquisition had occurred on January 1, 2006. The pro forma results for the 2007 and 2006 periods presented are the result of combining the statement of income for the Company with the revenues and direct operating expenses of the properties acquired adjusted for (1) assumption of ARO liabilities and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. ACQUISITIONS AND DIVESTITURES (Continued)

accretion expense for the properties acquired, (2) depletion expense applied to the adjusted basis of the properties acquired using the purchase method of accounting, (3) depreciation expense for other non-oil and natural gas assets acquired, (4) interest expense on added borrowings necessary to finance the acquisition, (5) amortization of deferred loan costs for new loan costs related to the financing of the acquisition, (6) dividends payable on the 5.75% Series A cumulative convertible perpetual preferred stock, (7) the related income tax effects of these adjustments based on the applicable statutory rates, and (8) the impact of common and preferred shares issued in public offerings completed to partially finance the January 2007 Acquisition. The pro forma information is based upon numerous assumptions, and is not necessarily indicative of future results of operations:

        Chapman Ranch Field Acquisition in 2006 —On December 12, 2006, the Company executed an agreement to acquire certain working interests in the Chapman Ranch Field in Nueces County, Texas from Kerr-McGee Oil & Gas Onshore LP ("Kerr-McGee"), a wholly owned subsidiary of Anadarko Petroleum Corporation. Upon the closing of the Kerr-McGee acquisition on December 28, 2006, the Company assumed operatorship of Chapman Ranch and added to the Company's existing working interest position in this field which it initially acquired in connection with two other acquisitions in late 2005. The final adjusted purchase price of $25.3 million was financed through borrowings under the Company's then-existing credit facility.

        Divestitures —During 2008, the Company completed sales of certain non-core assets, which included a pipeline and approximately 120 properties in Texas and Mississippi, to various buyers for aggregate proceeds of approximately $19.2 million. During January 2007, the Company divested a portion of its interest in a Louisiana well for $1.1 million. In 2006, the Company consummated the divestiture of its Buckeye properties located in Live Oak County, Texas for net proceeds of $0.6 million. Under full cost accounting rules, gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. Dispositions during 2008, 2007 and 2006 did not significantly alter the relationship between capitalized costs and proved reserves; therefore, the proceeds from these transactions were recognized as an adjustment of capitalized costs.

7. ASSET RETIREMENT OBLIGATIONS

        SFAS No. 143 requires that an asset retirement obligation ("ARO") associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs,

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7. ASSET RETIREMENT OBLIGATIONS (Continued)

excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at the Company's credit-adjusted risk-free interest rate. 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 Company adopted SFAS No. 143 on January 1, 2003, and the Company records an abandonment liability associated with its oil and natural gas wells when those assets are placed in service. The changes to the ARO during the periods ended December 31, 2008 and 2007 are as follows:

        ARO liabilities incurred during the year ended December 31, 2008 include obligations assumed for 54 properties that were successfully drilled during the year and several non-operated properties that were not previously identified. Liabilities settled during the year ended December 31, 2008 included 135 properties that were either plugged or sold. Revisions to the estimated liability relate to changes in working interests in certain properties.

8. ACCRUED LIABILITIES

        Below are the components of accrued liabilities as of December 31, 2008 and 2007:

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9. HEDGING AND DERIVATIVE ACTIVITIES

        Due to the volatility of oil and natural gas prices, the Company periodically enters into price-risk management transactions (e.g., swaps, collars and floors) for a portion of its expected oil and natural gas production to seek to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements may limit the Company's ability to benefit from increases in the price of oil and natural gas, it is also intended to reduce the Company's potential exposure to significant price declines. As a result of changes to the Company's 2008 production and the impact of certain divestitures, both of which reduced expected production as compared to that expected at the time the Company entered into the derivative contracts, the Company had approximately 115% and 190% of its 2008 natural gas and crude oil production, respectively, covered by derivative contracts. 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 were, at the time of their execution, intended to be used for trading or speculative purposes, but a portion of these instruments was subsequently deemed as such because of the decrease in the Company's 2008 production. These derivative 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. On a quarterly basis, the Company's management sets all of the Company's price-risk management policies, including volumes, types of instruments and counterparties. These policies are implemented by management through the execution of trades by the Chief Financial Officer after consultation and concurrence by the President and Chairman of the Board. The Board of Directors reviews the Company's policies and trades monthly.

        All of these price-risk management transactions are considered derivative instruments and accounted for in accordance with SFAS No. 133 (as amended). These derivative instruments are intended to hedge the Company's price risk and may be considered hedges for economic purposes, but certain of these transactions may not qualify for cash flow hedge accounting. All derivative instruments, other than those that meet the normal purchases and sales exception, are recorded on the balance sheet at fair value. The 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 OCI on the balance sheet. Rather they are immediately recorded in total revenue on the statement of operations. For those derivative instrument contracts that are designated and qualify for cash flow hedge accounting, the effective portion of the changes in the fair value of the contracts is recorded in OCI on the balance sheet and the ineffective portion of the changes in the fair value of the contracts is recorded in total revenue on the statement of operations, in either case, as such changes occur. When the hedged production is sold, the realized gains and losses on the contracts are removed from OCI and recorded in revenue. 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.

        During the first quarter of 2006, the Company began to apply mark-to-market accounting treatment to all outstanding derivative contracts, whereas cash flow hedge accounting treatment was applied to natural gas contracts prior to 2006. As a result, the changes in fair value are not deferred through other comprehensive income, but rather recorded in revenue immediately as unrealized gains

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. HEDGING AND DERIVATIVE ACTIVITIES (Continued)

or losses. The Company continues to evaluate 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 always used mark-to-market accounting treatment for its crude oil contracts.

        For the years ended December 31, 2008, 2007 and 2006, the Company included in revenue realized and unrealized losses related to its derivative contracts. For the three years ended December 31, 2008, 2007 and 2006, the Company included in total revenue the following realized and unrealized gains and losses:

        The fair value of outstanding derivative contracts reflected on the balance sheet were as follows:

---

(1)

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

(2)

The Company's crude oil contracts were 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 these contracts and the change in fair value is reflected in total revenue.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. FAIR VALUE MEASUREMENTS

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

Valuation Techniques

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

•

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



•

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



•

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

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

Input Hierarchy

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

•

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



•

Level 2 —Inputs (other than quoted prices included in Level I) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. FAIR VALUE MEASUREMENTS (Continued)

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 December 31, 2008. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

        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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. FAIR VALUE MEASUREMENTS (Continued)

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

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

Fair Value on a Nonrecurring Basis

        In February 2008, the FASB issued FSP 157-2, which postpones the effective date of SFAS No. 157 for non-financial assets and liabilities. Therefore, the Company has not adopted the provisions of SFAS No. 157 for its asset retirement obligations ("ARO"). 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 1, in accordance with SFAS No. 143, and the Company expects to expand its disclosures regarding its ARO upon complete adoption of SFAS No. 157.

11. 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 only $320 million was available under the borrowing base at the time of closing. The Revolving Facility has a letter of credit sub-limit of $20 million. The Revolving Facility's original maturity was scheduled for January 31, 2011. In connection with the Revolving Facility, the Company paid the Lenders fees in an amount equal to 1.00% of the initial borrowing base, or $3.2 million, on January 31, 2007. The Company also paid approximately $0.6 million for certain other administrative fees, legal fees, fronting fees and work fees in connection with the Revolving Facility. The aggregate fees of $3.8 million (of which $0.1 million was paid in December 2006) were recorded to deferred loan costs and are being amortized over the maturity of the Revolving Facility.

        At December 31, 2008, borrowings under the Revolving Facility bore interest at either LIBOR plus an applicable margin ranging from 1.25% to 2.5% or Prime plus a margin of up to 0.25%, with an unused commitment fee ranging from 0.50% to 0.25%. At December 31, 2008, the interest rates applied to the Company's outstanding Prime and LIBOR borrowings were 3.75% and 4.33%, respectively. As of December 31, 2008, $239 million in total borrowings were outstanding under the Revolving Facility. The borrowing base was reduced from $320 million to $300 million during the fourth quarter of 2007 and the conforming borrowing base was reduced from $300 million to $250 million. In early May 2008, the Company's Revolving Facility borrowing base and conforming borrowing base were redetermined by the Lenders and set at $250 million and $225 million,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. DEBT (Continued)

respectively. These reductions were 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.

        On July 11, 2008, in connection with the proposed merger with Chaparral, the Company entered into a Consent Agreement (the "Chaparral Consent"). Pursuant to the Chaparral Consent and subject to the terms thereof, the Lenders deferred their right to conduct a borrowing base redetermination on or before June 30, 2008 and agreed to conduct the redetermination on October 31, 2008. The Company paid the Lenders a fee of approximately $0.4 million in connection with the deferral of the redetermination. On November 5, 2008, the Lenders agreed to delay the interim redetermination from October 31, 2008 until November 15, 2008. In consideration for this deferral, the Lenders placed a restriction upon the borrowing base such that it was effectively lowered to $240 million until the interim redetermination occurred. Pursuant to the terms of the Revolving Facility, upon completion of the redetermination, the Company's borrowing base would also be the conforming borrowing base. This redetermination process was completed in January 2009 and the Lenders established a new borrowing base under the Revolving Facility of $125 million, resulting in a deficiency of $114 million (the "Deficiency"). As required by the Revolving Facility, the Company elected to prepay the Deficiency in six equal monthly installments, with the first $19 million installment being due on February 9, 2009. On February 9, 2009, the Company entered into a Consent and Agreement (the "February Consent") among the Company and the Lenders 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 $19 million installment payments to be due on August 10, 2009. In connection with the February Consent, the Company agreed to prepay $5.0 million of its 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 the prepayments to be applied on a pro rata basis to reduce the remaining six $19 million deficiency payments. On March 10, 2009, the Company entered into a Consent and Agreement (the "March Consent") with the Lenders under the Revolving Facility, which provided, among other things, for the extension of the due date for the first installment to repay the Deficiency from March 10, 2009 to March 17, 2009. Notwithstanding such extension, the Company agreed with the Lenders that each of the other five equal installment payments required to eliminate the Deficiency would be due and payable as provided for in the February Consent.

        On March 16, 2009, the Company entered into an amended Consent and Agreement (the "Amended Consent") which provides, among other things, (1) that the Company will 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 fails 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 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 our 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. DEBT (Continued)

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 will 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% as of March 16, 2009), (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 requirment. The Amended Consent also eliminates the six $19 million deficiency payments which were contemplated by the February Consent and the March Consent. To comply with the terms of the Amended Consent, the Company anticipates that it will need to (i) sell select individual assets prior to May 31, 2009 to enable us to make the $25 million payment which is due on May 31, 2009, and/or (ii) negotiate a commitment letter with a new lender or group of lenders prior to May 15, 2009 in an amount sufficient to repay all of the Company's obligations under the Revolving Facility on or before June 30, 2009, and/or (iii) have negotiated the sale, merger or other business combination involving us which results in the repayment of all of the Company's obligations under the Revolving Facility prior to May 15, 2009 and to have closed such transaction on or before June 30, 2009. The Amended Consent limits the making of capital expenditures and the Company anticipates a severe curtailment of its drilling plans and other capital expenditures in 2009.

        If the Company breaches any of the provisions of the Amended Consent, its Lenders will be entitled to declare an event of default, at which point the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, would become immediately due and payable. In any event, the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to the Lenders, will be payable on June 30, 2009 unless earlier paid or a further extension with respect to payment is negotiated with the Lenders. The Lenders may take action to enforce their rights with respect to the outstanding obligations under the Revolving Facility. Because substantially all of the Company's assets are pledged as collateral under the Revolving Facility, if the Lenders declare an event of default, they would be entitled to foreclose on and take possession of the Company's assets. In such an event, the Company may be forced to liquidate or to otherwise seek protection under Chapter 11 of the U.S. Bankruptcy Code. These matters, as well as the other risk factors related to the Company's liquidity and financial position raise substantial doubt as to our ability to continue as a going concern (see Note 1). With respect to the Company's compliance with the Amended Consent, there can be no assurance that the Company will be able to further negotiate the terms of the Amended Consent or negotiate a further restructuring of the related indebtedness or that it will be able to either make any required payments when they become due. Moreover, there can be no assurance that the Company will be successful in its efforts to comply with the terms of the Amended Consent, including its ongoing efforts to evaluate and assess our various financial and strategic alternatives (which may include the sale of some or all of our assets, a merger or other business combination involving the Company, or the restructuring or recapitalization of the Company). If such efforts are not successful, the Company may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

        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,

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limitations on additional borrowings, sales of oil and natural gas properties or other collateral, and engaging in merger or consolidation transactions. The Revolving Facility restricts dividends on common stock and certain distributions of cash or properties and certain liens but no longer contains any financial covenants as a result of the Amended Consent.

        The Revolving Facility includes 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.

12. SUBSEQUENT EVENTS

        During January 2009, the Company announced that the Lenders to its Revolving Facility had completed their borrowing base redetermination and reduced the Company's borrowing base on its Revolving Facility to $125 million, resulting in a $114 million borrowing base deficiency (see Note 11 above). On March 10, 2009, the Company entered into the March Consent with the Lenders to its Revolving Facility (see Note 11 above). In addition, on March 16, 2009, the Company entered into the Amended Consent with the Lenders under the Revolving Facility (see Note 11 above).

        Also in January 2009, the Company retained an investment banking firm to assist further in an evaluation of its strategic alternatives, including a capital restructuring for the Company. Additionally, the Company has engaged a law firm to act as the Company's legal advisor in connection with the evaluation of its strategic alternatives and to represent the Company generally as primary outside counsel in its ongoing corporate and securities matters. There can be no assurance that the Company will be successful in pursuing any strategic alternatives. Moreover, there can be no assurance that the Company's ongoing efforts to evaluate and assess its various financial and strategic alternatives (which may include the sale of some or all of the Company's assets, a merger or other business combination involving the Company, restructuring of the Company's debt or the issuance of additional equity or debt) will be successful. If such efforts are not successful, the Company may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

        Appointment of Chief Financial Officer —Effective as of January 26, 2009, the Board of Directors of the Company, appointed Gary L. Pittman as Executive Vice President and Chief Financial Officer of

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the Company. Mr. Pittman replaces the Company's Acting Chief Financial Officer, C.W. MacLeod, who will continue his role with the Company as Senior Vice President, Business Development and Planning.

13. SHELF REGISTRATION STATEMENT

        In the third quarter 2007, the SEC declared effective the Company's registration statement filed with the SEC that registered securities of up to $500 million of any combination of debt securities, preferred stock, common stock, warrants for debt securities or equity securities of the Company and guarantees of debt securities by the Company's subsidiaries. Net proceeds, terms and pricing of the offering of securities issued under the shelf registration statement will be determined at the time of the offerings. The shelf registration statement does not provide assurance that the Company will or could sell any such securities. The Company's ability to utilize the shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities will depend upon, among other things, market conditions and the existence of investors who wish to purchase the Company's securities at prices acceptable to the Company. As of March 11, 2009, the Company had $500 million available under its shelf registration statement. However, because the aggregate market value of the Company's outstanding common stock is less than $75 million, the type and amount of any securities offering under the registration statement may be limited.

        In January 2007, the Company completed concurrent offerings of 10.925 million shares of its common stock and 2.875 million shares of 5.75% Series A cumulative convertible perpetual preferred stock. The shares were offered to the public at a price of $13.25 per share of common stock and $50.00 per share of preferred stock. The Company received net proceeds of approximately $276.5 million from the offerings ($138.1 million from the common offering and $138.4 million from the preferred offering), after deducting underwriting discounts and commissions and the expenses of the offerings. These proceeds were used to partially finance the January 2007 Acquisition and to refinance the prior credit facility.

14. PREFERRED STOCK

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

        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

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legally available to pay dividends and the Board of Directors or an authorized committee of the Board declares a dividend payable, the Company pays 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 did not declare a dividend in the fourth quarter of 2008 due to the Company's current reduced liquidity. Cumulative dividends in arrears at December 31, 2008 amounted to $1.7 million.

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

        Liquidation preference.     In the event of the Company's voluntary or involuntary liquidation, winding-up or dissolution, each holder of Convertible Preferred Stock will be entitled to receive and to be paid out of the Company's assets available for distribution to its stockholders, before any payment or distribution is made to holders of junior stock (including common stock), but after any distribution on any of its 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.     The Company's 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 at the applicable conversion rate, but only if the closing sale price of its common stock for 20 trading days within a period of 30 consecutive trading days ending on the trading day immediately preceding the date the Company gives the conversion notice equals or exceeds 130% of the conversion price in effect on each such trading day.

        Optional redemption.     If fewer than 15% of the shares of Convertible Preferred Stock issued in the January 2007 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

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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 of conversion. 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 herein), 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 its 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

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indirectly, more than 50% of all classes of common equity of the continuing or surviving corporation or transferee immediately after the event shall not be a fundamental change;

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

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

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

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

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

•

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



•

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



•

reclassify any of the Company's 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.

15. COMMITMENTS AND CONTINGENCIES

        Commitments —At December 31, 2008, the Company was obligated under non-cancelable operating leases. Following is a schedule of the remaining future minimum lease payments under these leases:

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        Rent expense for the years ended December 31, 2008, 2007 and 2006 was approximately $1.1 million, $0.9 million, and $0.7 million, respectively.

        As described in Note 11, the Company has significant repayments of its outstanding debt due by June 30, 2009.

        As described in Note 2, the Company has natural gas delivery commitments to Frontier for which a liability of approximately $2.0 million was recorded in long-term liabilities during the fourth quarter of 2008. The Company also has natural gas delivery commitments to Integrys for approximately $550,000 plus interest, but management believes the Company can meet this delivery commitment based on estimated anticipated production.

        Contingencies —From time to time the Company is a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, the Company is not currently a party to any proceeding that it believes, if determined in a manner adverse to the Company, could have a material adverse effect on the Company's financial condition, results of operations or cash flows except as set forth below.

        David Blake, et al. v. Edge Petroleum Corporation —On September 19, 2005, David Blake and David Blake, Trustee of the David and Nita Blake 1992 Children's Trust, filed suit against the Company in state district court in Goliad County, Texas alleging breach of contract for failure and refusal to transfer overriding royalty interests to plaintiffs in several leases in the Nita and Austin prospects in Goliad County, Texas and failure and refusal to pay monies to Blake pursuant to such overriding royalty interests for wells completed on the leases. The plaintiffs seek relief of (1) specific performance of the alleged agreement, including granting of overriding royalty interests by us to Blake; (2) monetary damages for failure to grant the overriding royalty interests; (3) exemplary damages for his claims of business disparagement and slander; (4) monetary damages for tortious interference; and (5) attorneys' fees and court costs. Venue of the case was transferred to Harris County, Texas by agreement of the litigants. The Company's subsidiaries, Edge Petroleum Exploration Company, Edge Petroleum Operating Company and Edge Petroleum Production Company, were also added as defendants. The Company filed a counterclaim against plaintiff and joined various related entities that are controlled by Blake, seeking lease interests in which the Company contends it had been wrongfully denied participation and also claiming that proprietary information was misappropriated. The parties have moved for summary judgment on each other's claims and counterclaims, which the trial court has denied as to both sides. In November 2007, the Company filed a separate motion for summary judgment based on the statute of frauds and; the court has not yet ruled on this separate motion. In June 2008, the Plaintiffs filed a Sixth Amended Petition conditionally adding claims for certain prospects that had been previously settled by means of a Compromise and Settlement Agreement (the "Settlement Agreement"), entered in settlement of prior litigation among some of the parties, but only to the extent that rescission of the prior Settlement Agreement was being sought by the Company. The Company is not seeking rescission of the prior Settlement Agreement and responded accordingly in its Fourth Amended Original Counterclaim and Claims Against Additional Parties filed on October 16, 2008. On October 17, 2008, the plaintiffs filed their Seventh Amended Petition adding a claim for breach of the Settlement Agreement. The trial, originally scheduled to begin September 10, 2007, has been reset several times, most recently for December 8, 2008, and will be reset in 2009 by the newly-elected judge of the 215th Judicial District Court. In December 2008, one of the Blake counter-defendants filed a motion to arbitrate, which motion has not been heard by the court. Extensive written

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discovery has occurred in the case, and the parties are engaging in fact and expert witness depositions. The Company has responded and will continue to respond aggressively to this lawsuit, and believes it has meritorious defenses and counterclaims.

        Diana Reyes, et al. v. Edge Petroleum Operating Company, Inc., et al. —On January 8, 2008, the Company was served with a wrongful death action filed in Hidalgo County, Texas. Plaintiffs allege negligence and gross negligence resulting from a fatality accident at the Slick State B-12 well site, on the Company's Bloomberg Flores lease in Starr County, Texas. The plaintiffs are the widow and minor children of Mr. Reyes, who was killed in a one-car fatality accident on August 5, 2007. Mr. Reyes was an employee of Payzone Logging, a vendor of the Company. In September 2008, the defendants in this case, including the Company, reached a settlement with the plaintiffs in the amount of $175,000, all of which was paid by third party insurance. Neither the Company nor its insurance carrier was required to contribute to the settlement pool. This matter was dismissed by the court on December 17, 2008.

        Mary Jane Carol Trahan Champagne, et al. v. Edge Petroleum Exploration Company, et al. —On September 19, 2008 the Company was sued in state district court in Vermilion Parish, Louisiana by Mary Jane Trahan, Carol Trahan Champagne and 29 other plaintiffs alleging breach of obligations under mineral leases in Vermilion Parish regarding the Trahan No. 1 well and the Trahan No. 3 well (MT RC SUB reservoir). Plaintiffs are seeking unspecified damages for lost revenue, lost royalties and devaluation of property interest sustained as a result of the defendants' alleged negligent and improper drilling operations on the Trahan No. 1 well and the Trahan No. 3 well, including alleged failure to prevent underground water from flooding and destroying plaintiffs' portion of the reservoir beneath plaintiffs' property. Plaintiffs also allege defendants failed to "block squeeze" sections of the Trahan No. 3 well as would a prudent operator. This lawsuit, previously removed from the state court to the federal district court for the Western District of Louisiana, Lafayette Division, has been remanded to state court. The Company's insurance carrier has retained counsel to represent the Company in this matter. The Company has not established a reserve with respect to this claim and it is not possible to determine what, if any, its ultimate exposure might be in this matter. The Company intends to vigorously defend itself in this lawsuit.

        John Lemke, et al. v. Edge Petroleum Corporation —In October 2008, the Company was sued by alleged assignees of Continental Seismic over an alleged contract to receive a royalty of two-tenths of one percent in certain alleged areas developed for oil and gas in South Louisiana. The Company has filed an answer generally denying the allegations and raising the defenses of the statute of limitations bar and laches. No discovery has been served. The court recently entered a docket control order which establishes a discovery timetable and a trial date of November 30, 2009. The Company has not established a reserve with respect to this claim and has not determined what, if any, the Company's ultimate exposure might be in this matter. The Company will respond aggressively to this lawsuit, and believes it has meritorious defenses.

16. SALES TO MAJOR CUSTOMERS AND OPERATORS

        In accordance with SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information , public business enterprises are required to report financial and other information about operating segments of the entity. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for

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the purpose of allocating resources and assessing performance. Segment reporting is not applicable to the Company, as it has a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. The Company tracks only basic operational data by area and does not maintain complete separate financial statement information by area. The Company measures financial performance as a single enterprise and not on an area-by-area basis. Throughout the year, the Company allocates capital resources on a project-by-project basis, across the entire asset base to maximize profitability without regard to individual areas or segments.

        SFAS No. 131 also establishes standards for disclosures about major customers. The Company sold natural gas and crude oil production representing 10% or more of its total revenues for the years ended December 31, 2008, 2007, and 2006 as listed below:

---

*

Zero or less than 1%.



(1)

Integrys Energy Services is an agent that sells our production to other purchasers on our behalf.

NOTE: Amounts disclosed are approximations and those that are less than 10% are presented for information and comparison purposes only. Also these percentages do not consider the effects of financial derivative instruments.

        In the exploration, development and production business, production is normally sold to relatively few customers. A significant portion of the Company's sales are made on its behalf by the operators of the properties and therefore these entities may be listed above. Substantially all of the Company's customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions and the price of certain commodities such as natural gas and crude oil, the cost of which is passed through to the customer. However, based on the current demand for natural gas and crude oil and the fact that alternate purchasers are readily available, the Company believes that the loss of any of our major purchasers would not have a long-term material adverse effect on its operations.

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17. INCOME TAXES

        Income tax expense (benefit), including deferred amounts, is summarized as follows:

        Total income taxes differed from the amounts computed by applying the statutory income tax rate to income before income taxes. The sources of these differences are as follows:

        The effect of share-based compensation expense for tax purposes in excess of or less than amounts recognized for financial accounting purposes was recorded directly to stockholders' equity in the amounts of approximately $(0.2) million and $0.5 million for 2007 and 2006, respectively. For 2008, the effect of share-based compensation expense for tax purposes was less than amounts recognized for financial accounting purposes and was recorded as a tax expense in the amount of approximately $0.6 million.

        Deferred income taxes reflect the tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts calculated for income tax purposes in accordance with SFAS No. 109. Under this method, future income tax assets and liabilities are determined based on the "temporary differences" between the accounting basis and the income tax basis of the Company's assets and liabilities measured using the currently enacted, or substantially enacted, income tax rates in effect when these differences are expected to reverse.

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Significant components of the Company's deferred tax liabilities and assets as of December 31, 2008 and 2007 are as follows:

        At December 31, 2008, total deferred taxes included $43.7 million of federal and $2.0 million of state net operating loss ("NOL") carryforwards. In addition to the deferred tax assets associated with NOLs, the Company has additional net deferred tax assets of approximately $65.0 million related to both federal and state tax positions. 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

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surrounding the Company's Revolving Facility and related Amended Consent (see Note 11), management is not able to determine that it is more likely than not that the deferred tax assets will be realized and therefore has established a full valuation allowance to reduce the net deferred tax asset to zero at December 31, 2008. The Company will continue to assess the valuation allowance against deferred 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 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.

        Tax carryforwards at December 31, 2008, which are available for utilization on future income tax returns, are as follows:

        The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. The Company's tax periods are open with the exception of Texas which is audited through the 2007 report years. The Texas Comptroller's Office began an audit of the 2004 through 2007 report years during the latter part of 2007, completing the audit in 2008 with no adjustment proposed.

        Upon adoption of FIN 48 on January 1, 2007, the Company recognized a liability of $534,035 which was a reduction in the January 1, 2007 retained earnings balance. During 2008, the Company recorded an income tax benefit of approximately $0.4 million as a result of the conclusion of a state

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audit where no prior benefit was taken. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

        The amount recorded does not include interest as the anticipated adjustments more likely than not will result in no current tax due as a result of NOL carryovers. The unrecognized tax benefits of approximately $0.1 million would impact the Company's effective tax rate if ultimately recognized. The Company does not expect the amount of unrecognized tax benefits to materially change in 2009. The Company recognizes interest and penalties related to unrecognized tax benefits in tax expense. The Company recognized no interest or penalties during the year ended December 31, 2008.

18. EMPLOYEE BENEFIT PLANS

        Effective July 1, 1997, the Company established a defined-contribution 401(k) Savings & Profit Sharing Plan Trust (the "Plan") covering employees of the Company who are age 21 or older. The Company's matching contributions to the Plan are discretionary. For the years ended December 31, 2008, 2007 and 2006, the Company contributed approximately $0.5 million, $0.6 million, and $0.5 million, respectively, to the Plan.

19. EQUITY AND STOCK PLANS

        Public Offerings 2007 —In connection with two concurrent public offerings in January 2007, the Company issued approximately 2.9 million shares of preferred stock and approximately 10.9 million shares of common stock at gross prices of $50.00 and $13.25 per share, respectively. These offerings generated net proceeds to the Company, after underwriters' fees and direct costs of the offering, of $276.5 million. These shares were issued to generate funds to partially finance the January 2007 Acquisition (see Note 6).

        Share-Based Compensation —The Company established the Incentive Plan of Edge Petroleum Corporation (the "Incentive Plan") in conjunction with its initial public offering in March 1997. The Incentive Plan is discretionary and provides for the granting of awards, including options for the purchase of the Company's common stock and for the issuance of restricted and/or unrestricted common stock to directors, officers, employees and independent contractors of the Company. The options and restricted stock granted to date vest over periods of two to four years. The Company amended the Incentive Plan (i) in December 2003 to increase the shares available under the plan from 1.2 million shares to 1.7 million shares and (ii) in June 2006 to increase the shares available under the Plan from 1.7 million shares to 2.2 million shares. Of the aggregate 2.2 million shares of common stock reserved for grants under the Incentive Plan, 423,768 shares were available for future grants at

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. EQUITY AND STOCK PLANS (Continued)

December 31, 2008. The following nonqualified stock option awards and restricted stock unit grants were made under the Incentive Plan during each of the years indicated below:

---

(1)

Restricted stock awards granted, as presented above, are net of shares forfeited or cancelled during the corresponding year.

        As a component of his employment agreement with the Company, John Elias, CEO and Chairman of the Board, has been granted option awards and a restricted stock award outside of the Incentive Plan. Mr. Elias has also been granted options and restricted stock under the Incentive Plan. The options vest and become exercisable over a two year period subsequent to issue. The restricted stock is issued over three to four years in accordance with the award's vesting schedule. Compensation expense is amortized over the vesting period and offset to additional paid in capital ("APIC"). The amortization of compensation expense related to this award is included in general and administrative expenses on the consolidated statement of operations. Below is a summary of options and restricted stock grants made to Mr. Elias outside of the Incentive Plan:

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(1)

Exercise price equals the fair market value on the date of grant.

(2)

Expired unexercised in January 2009.

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. EQUITY AND STOCK PLANS (Continued)

(3)

Value was $7.75 per share, the market value on the date of grant.

        Effective January 1, 2006, the Company adopted SFAS No. 123(R) utilizing the modified prospective approach. Prior to the adoption of SFAS No. 123(R), the Company accounted for stock option grants in accordance with APB No. 25 using the intrinsic value method, and accordingly, recognized no compensation expense for stock option grants. In 1999, the Company repriced certain employee and director stock options. The Company accounted for these repriced stock options in accordance with FIN 44 which prescribed the variable plan accounting treatment for repriced options. Under variable plan accounting, compensation expense is adjusted for increases or decreases in the fair market value of the Company's common stock to the extent that the market value exceeds the exercise price of the option until the options are exercised, forfeited, or expire unexercised.

        Under the modified prospective approach, SFAS No. 123(R) applies to new awards and to awards that were outstanding on January 1, 2006 that are subsequently modified, repurchased or cancelled. Under the modified prospective approach, compensation cost recognized in the first quarter of fiscal 2006 includes compensation cost for all share-based payments granted prior to, but not yet vested, as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of SFAS No. 123 and compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123(R). Prior periods were not restated to reflect the impact of adopting the new standard. Share-based compensation costs for the years ended December 31, 2008, 2007 and 2006 were:

        The Company receives a tax deduction for certain stock options exercised during the period the options are exercised, generally for the excess of the price at which the options are sold over the exercise prices of the options. In addition, the Company receives a tax deduction for the compensation element of restricted stock grants that vest during the period, which is the vesting share price multiplied by the number of shares vesting. SFAS No. 123(R) requires that these excess tax benefits be reported in the consolidated statement of cash flows as financing activities. SFAS No. 123(R) provides that the excess tax benefit and credit to APIC for the windfall should not be recorded until the deduction reduces income taxes payable. Because the Company is in a net operating loss ("NOL") position for tax purposes, and does not have taxes payable at this time, it has not realized a tax benefit from the deduction. Therefore, the Company excludes these deductions from the windfall pool and does not present the tax benefits from the exercise of stock options as financing activities, but expects that certain amounts of windfall will be credited to APIC in future periods if the NOL carryforwards are utilized to reduce taxes payable.

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. EQUITY AND STOCK PLANS (Continued)

Stock Options

        There have been no stock option grants since 2004. For future grants, the Company expects to use the Black-Scholes option pricing model to estimate the fair value of stock options which requires the Company to make the following assumptions:

•

The risk-free interest rate is based on the applicable year Treasury bond at date of grant.



•

The dividend yield on the Company's common stock is assumed to be zero since the Company does not pay dividends.



•

The market price volatility of the Company's common stock is based on historical prices.



•

The term of the grants is based on the simplified method as described in SAB No. 107, Share-Based Payment .

        The assumptions above are based on multiple factors, including historical exercise patterns of employees in relatively homogenous groups with respect to exercise and post-vesting employment termination behaviors, expected future exercising patterns for these same homogeneous groups and the implied volatility of our stock price.

        In addition, the Company estimates a forfeiture rate at the inception of the option grant based on historical data and adjusts this prospectively as new information regarding forfeitures becomes available.

        For the year ended December 31, 2006, the Company recognized $68,937 in stock option compensation expense. All option grants were fully vested as of April 1, 2006; therefore, no further compensation expense associated with stock options will be expensed in future periods unless new grants are awarded. The total intrinsic value (current market price less the option strike price) of options exercised during the year ended December 31, 2006 was $1.5 million and the Company received $0.6 million in cash in connection with these exercises.

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. EQUITY AND STOCK PLANS (Continued)

        A summary of activity associated with the Company's stock options during the last three years follows:

        The Company determines the fair value of options at the date of grant using the Black-Scholes option pricing model. There were no options granted for the years ended December 31, 2008, 2007 and 2006. There were 100 options forfeited for the year ended December 31, 2007 and none for the years ended December 31, 2006 and 2008.

        The Black-Scholes option pricing model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. The Company's stock options have characteristics significantly different from those of traded options and because changes in the subjective input assumptions can materially affect the fair value estimate, it is management's opinion that the valuations afforded by the existing models are different from the value that the options would realize if traded in the market.

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. EQUITY AND STOCK PLANS (Continued)

        A summary of additional information related to options outstanding as of December 31, 2008 follows:

---

(1)

Expired unexercised in January 2009.

Restricted Stock

        In addition to stock options, the Company issues restricted stock and restricted stock units. For awards issued to date, shares of common stock associated with the restricted stock awards will be issued, subject to continued employment, ratably over three or four years in accordance with the award's vesting schedule, beginning on the first or second anniversary of the date of grant. Compensation expense from restricted stock and restricted stock units is amortized over the vesting period and offset to APIC. The share-based expense for these awards was determined based on the market price of the Company's stock at the date of grant applied to the total number of shares that were anticipated to fully vest and then amortized over the vesting period. As of December 31, 2008, the Company had unamortized share-based compensation of $2.3 million associated with these awards. The cost is expected to be recognized over a weighted-average period of approximately two years. The total fair value of shares vested during the year ended December 31, 2008 was $0.3 million. Upon adoption of SFAS No. 123(R), the Company recorded an immaterial cumulative effect of change in accounting principle as a result of the change in policy from recognizing forfeitures as they occur to recognizing expense based on the Company's expectation of the awards that will vest over the requisite service period for its restricted stock and restricted stock unit awards. This amount was recorded as compensation cost in general and administrative expenses in the consolidated statement of operations.

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. EQUITY AND STOCK PLANS (Continued)

        A summary of the status of the unvested shares of restricted stock and changes during 2008, 2007 and 2006 is presented below:

        The aggregate intrinsic value of restricted stock vested during 2008 was approximately $0.8 million.

        Computation of Earnings per Share —The Company accounts for earnings per share in accordance with SFAS No. 128, which establishes the requirements for presenting earnings per share ("EPS"). SFAS No. 128 requires the presentation of "basic" and "diluted" EPS on the face of the statement of operations. Basic EPS amounts are calculated using the weighted average number of common shares outstanding during each period. Diluted EPS assumes the exercise of all stock options, warrants and convertible securities having exercise prices less than the average market price of the common stock during the periods, using the treasury stock method. When a loss from continuing operations exists, as in the periods presented, potential common shares are excluded in the computation of diluted EPS because their inclusion would result in an anti-dilutive effect on per share amounts.

        Diluted EPS also includes the effect of convertible securities by application of the "if-converted" method. Under this method, if an entity has convertible preferred stock outstanding, the preferred dividends applicable to the convertible preferred stock are added back to the numerator. The convertible preferred stock is assumed to have been converted at the beginning of the period (or at time of issuance, if later) and the resulting common shares are included in the denominator of the EPS calculation. In applying the if-converted method, conversion is not assumed for purposes of computing diluted EPS if the effect would be anti-dilutive. During 2008 and 2007, conversion of the 5.75%

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. EQUITY AND STOCK PLANS (Continued)

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

---

(1)

In the calculation of diluted EPS for the year ended December 31, 2008, the 8.7 million shares of common stock resulting from an assumed conversion of the Company's 5.75% Series A cumulative convertible perpetual preferred stock and 24,718 equivalent shares of the Company's restricted stock units and common stock options were excluded because the conversion would be anti-dilutive.

(2)

In the calculation of diluted EPS for the year ended December 31, 2007, the 8.7 million shares of common stock resulting from an assumed conversion of the Company's 5.75% Series A cumulative convertible perpetual preferred stock and 252,853 equivalent shares of the Company's restricted stock units and common stock options were excluded because the conversion would be anti-dilutive.

(3)

In the calculation of diluted EPS for the year ended December 31, 2006, 425,567 equivalent shares of the Company's restricted stock units and common stock options were excluded because inclusion of the shares would be anti-dilutive.

        Associated with the exercise of stock options and vesting of restricted stock units, the Company received a tax benefit of approximately $0.5 million in 2006. During 2007, the Company recorded charges associated with the exercise of stock options and vesting of restricted stock units of approximately $0.2 million. The tax benefit or charge is recorded as an increase or decrease in APIC.

20. RELATED PARTY TRANSACTIONS

        The transactions described below were with affiliates, and it is possible that the Company would have obtained different terms from a truly unaffiliated third-party. In addition, see Note 15 regarding certain disputes with entities involving Mr. Sfondrini (a director of the Company).

        Affiliates' Ownership in Prospects —Edge Group Partnership, a Connecticut general partnership composed of the three Connecticut limited partnerships (Edge I Limited Partnership, The Edge II Limited Partnership, and The Edge III Limited Partnership) whose general partners are Mr. Sfondrini

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. RELATED PARTY TRANSACTIONS (Continued)

and a corporation wholly owned by him; Edge Holding Company, L.P., a limited partnership of which Mr. Sfondrini and a corporation wholly owned by him are the general partners; Edge Option I Limited Partnership, Edge Option II Limited Partnership and Edge Option III Limited Partnership, limited partnerships whose general partners are Mr. Sfondrini and a corporation controlled by him; Andex Energy Corporation and Texedge Energy Corporation, corporations of which Mr. Andrews (a director of the Company) is an officer and members of his immediate family hold ownership interests; Mr. Raphael (a former director of the Company) and Essex II Joint Venture, own certain working interests in the Company's Nita and Austin Prospects and certain other wells and prospects operated by the Company. These working interests aggregate 7.19% in the Austin Prospect, 6.27% in the Nita Prospect and are negligible in other wells and prospects. These working interests bear their share of lease operating costs and royalty burdens on the same basis as the Company. In addition, Bamaedge, L.P., a limited partnership of which Andex Energy Corporation is the general partner, and Mr. Raphael also hold overriding royalty interests with respect to the Company's working interest in certain wells and prospects. Neither Mr. Raphael nor Bamaedge L.P. has an overriding interest in excess of 0.075% in any one well or prospect. Essex I Joint Venture and Essex II Joint Venture (a joint venture of which Mr. Sfondrini and a company wholly owned by him are the managers) own royalty and overriding royalty interests in various wells operated by the Company. The combined royalty and overriding royalty interests of the Essex I and Essex II Joint Ventures do not exceed 6.2% in any one well or prospect. In September 2006, the Essex I and Essex II Joint Ventures sold all of their interests in wells operated by the Company except for one well in which Essex II has a 1% gross working interest. Mr. Tugwell (an officer of the Company) and Mr. Gabrisch (a former vice president of the Company) own overriding royalty interests in various wells as a result of awards they received prior to 2000 when the Company had an overriding royalty program in effect for certain key employees. The gross amounts paid or accrued to these persons and entities by the Company in 2008 (including net revenue, royalty and overriding royalty interests) and the amounts these same persons and entities paid

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. RELATED PARTY TRANSACTIONS (Continued)

to the Company for their respective share of lease operating expenses and other costs are set forth in the following table:

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*

Not relevant

(1)

In the case of Essex I and II Royalty Joint Ventures, amount includes royalty income in addition to working interest and overriding royalty income. The Company sold its interest in these entities in 2003, but Mr. Sfondrini maintains an indirect interest in these entities.

(2)

Edge Group Partnership and Edge Group Holding Co., L.P. (partnerships controlled by John Sfondrini, a director of the Company) sold and/or transferred all of their interests in the Company's operated properties during 2008.

(3)

Mark G. Gabrisch left the Company in 2006, and therefore was no longer deemed a related party in 2007 and 2008.

(4)

Stanley Raphael retired from the Board of Directors in 2007, and therefore was no longer deemed a related party in 2008.

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. RELATED PARTY TRANSACTIONS (Continued)

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(1)

Edge Group Partnership and Edge Group Holding Co., L.P. (partnerships controlled by John Sfondrini, a director of the Company) sold and/or transferred all of their interests in the Company's operated properties during 2008.

(2)

Stanley Raphael retired from the Board of Directors in 2007, and therefore was no longer deemed a related party in 2008.

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

        A summary of non-cash investing and financing activities for the years ended December 31, 2008, 2007 and 2006 is presented below:

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

21. SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES (Continued)

        For the years ended December 31, 2008, 2007 and 2006, the non-cash portion of Asset Retirement Costs was $0.5 million, $3.0 million, and $0.4 million, respectively. A supplemental disclosure of cash flow information for the years ended December 31, 2008, 2007 and 2006 is presented below:

22. SUPPLEMENTAL FINANCIAL QUARTERLY RESULTS (unaudited):

        The sum of the individual quarterly basic and diluted earnings (loss) per share amounts may not agree with year-to-date basic and diluted earnings (loss) per share amounts as a result of each period's computation being based on the weighted average number of common shares outstanding during that period.

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(1)

Operating expenses in the third and fourth quarters of 2008 include non-cash impairment charges of $129.5 million ($84.2 million, net of tax) and $233.3 million ($215.8 million, net of tax), respectively, as a result of a full-cost ceiling test. See the full-cost ceiling test discussion in Note 2.

(2)

The Company completed its largest ever acquisition during January 2007, which had a significant impact on results in 2007 (see Note 6).

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

23. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (unaudited)

        This footnote provides unaudited information required by SFAS No. 69, Disclosures About Oil and Natural Gas Producing Activities . The Company's oil and natural gas properties are located within the United States of America, which constitutes one cost center.

        Capitalized Costs —Capitalized costs and accumulated depletion and impairments relating to the Company's oil and natural gas producing activities, all of which are conducted within the continental United States, are summarized below:

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(1)

Asset retirement costs associated with the plugging and abandonment liability related to SFAS No. 143 (see Note 7) are included in this line.

        Costs Incurred —Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below:

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(1)

Included in the development costs line item are the asset retirement costs associated with the plugging and abandonment liability related to SFAS No. 143 (see Note 7).

        Net costs incurred excludes sales of proved oil and natural gas properties which 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.

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

23. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (unaudited) (Continued)

        Results of Operations —Results of operations for the Company's oil and natural gas producing activities are summarized below:

---

(1)

The tax effects have been computed using the statutory tax rate without consideration of valuation allowances, if any, recorded on related deferred tax assets as discussed in Note 17.

        Reserves —Proved reserves are estimated 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. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. Proved oil and natural gas reserve quantities and the related discounted future net cash flows before income taxes (see Standardized Measure) for the periods presented are based on estimates prepared by Ryder Scott Company and W.D. Von Gonten & Co., independent petroleum engineers. Such estimates have been prepared in accordance with guidelines established by the SEC.

        The Company's reserves decreased in 2008 due to lower commodity prices, production, property sales and revisions to previous estimates. The Company was unable to replace the production the Company generated due to its reduced capital spending program and higher drilling and operating costs. However, the decrease was partially offset by extensions and discoveries that resulted from the drilling of 25 gross (8.74 net) apparent successess recompletion of one well, and the addition of one proved undeveloped ("PUD") location. Revisions to previous estimates during 2008 were primarily due to (1) commodity pricing that was significantly lower than year-end 2007, causing a number of PUD locations to be uneconomic and shortening the economic life of many other properties, (2) results of actual drilling and recompletion operations and updated technical analysis, (3) updates to shrink and differential factors and (4) updated performance (both positive and negative) on existing producing wells. The Company's net ownership in estimated quantities of proved oil and natural gas reserves and

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

23. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (unaudited) (Continued)

changes in net proved reserves, all of which are located in the continental United States, are summarized below.

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

23. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (unaudited) (Continued)

        Standardized Measure —The Standardized Measure of Discounted Future Net Cash Flows relating to the Company's ownership interests in proved oil and natural gas reserves for each of the three years ended December 31, 2008 is shown below:

---

(1)

As of December 31, 2008, the Company was not in a tax paying position and therefore income taxes are not applicable to this presentation.

        In accordance with SEC regulations, the oil and natural gas prices in effect at December 31, 2008, adjusted for basis and quality differentials, are applied to year-end quantities of proved oil and natural gas reserves to compute future cash flows. The base prices before adjustments were as follows:

        Future oil and natural gas operating expenses and development costs are computed primarily by the Company's internal petroleum engineers and are provided to external independent petroleum engineers as estimates of expenditures to be incurred in developing and producing the Company's proved oil and natural gas reserves at the end of the year, based on year-end costs and assuming the continuation of existing economic conditions.

        Future income taxes are based on year-end statutory rates, adjusted for net operating loss carryforwards and tax credits. A discount factor of 10% was used to reflect the timing of future net cash flows. The Standardized Measure of Discounted Future Net Cash Flows is not intended to represent the replacement cost or fair market value of the Company's oil and natural gas properties.

        The Standardized Measure of Discounted Future Net Cash Flows does not purport, nor should it be interpreted, to present the fair value of the Company's oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

23. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (unaudited) (Continued)

        Changes in Standardized Measure —Changes in Standardized Measure of Discounted Future Net Cash Flows relating to proved oil and gas reserves are summarized below:

        Sales of oil and natural gas, net of oil and natural gas operating expenses are based on historical pre-tax results. Sales of oil and natural gas properties, extensions and discoveries, purchases of minerals in place and the changes due to revisions in standardized variables are reported on a pre-tax discounted basis, while the accretion of discount is presented on an after-tax basis.

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INDEX TO EXHIBITS

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*

Filed herewith.

†

Denotes management or compensatory contract, arrangement or agreement.

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