UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2008

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from               to         

Commission file number 0-22149

EDGE PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

(713) 654-8960

(Registrant’s telephone number, including area code)

Indicate by checkmark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

x Yes o No

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

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

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

EDGE PETROLEUM CORPORATION

Table of Contents

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EDGE PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

See accompanying notes to consolidated financial statements.

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EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

See accompanying notes to consolidated financial statements.

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EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

See accompanying notes to consolidated financial statements.

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EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

See accompanying notes to consolidated financial statements.

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EDGE PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The financial statements included herein have been prepared by Edge Petroleum Corporation, a Delaware corporation (“we”, “our”, “us” or the “Company”), without audit pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), and reflect all adjustments which are, in the opinion of management, necessary to present a fair statement of the results for the interim periods on a basis consistent with the annual audited consolidated financial statements.  All such adjustments are of a normal recurring nature.  The results of operations for the interim periods are not necessarily indicative of the results to be expected for an entire year.  Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to such rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading. These financial statements should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2007.

Strategic Assessment 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 assessment process, which included a thorough review and assessment of the Company’s strengths and weaknesses, competitive position and asset base, reporting that after careful analysis, management and the Board of Directors believed that the best route to maximizing stockholder value at that time was to focus on an assessment of a potential merger or sale of Edge. That process is ongoing .   A decision on any particular course of action has not been made and there can be no assurance that the Board of Directors will authorize any transaction.

Oil and Natural Gas Properties - Investments in oil and natural gas properties are accounted for using the full-cost method of accounting. The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry.  There are two allowable methods of accounting for oil and gas business activities:  the successful-efforts method and the full-cost method. There are several significant differences between these methods. Among these differences is that, under the successful-efforts method, costs such as geological and geophysical (“G&G”), exploratory dry holes and delay rentals are expensed as incurred whereas under the full-cost method these types of charges are capitalized to their respective full-cost pool. In accordance with the full-cost method of accounting, all costs associated with the exploration, development and acquisition of oil and natural gas properties, including salaries, benefits and other internal costs directly attributable to these activities are capitalized within a cost center.  The Company’s oil and natural gas properties are located within the United States of America, which constitutes one cost center. The Company also capitalizes a portion of interest expense on borrowed funds.

In the measurement of impairment of oil and gas properties, the successful-efforts method follows the guidance provided in Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets , where the first measurement for impairment is to compare the net book value of the related asset to its undiscounted future cash flows using commodity prices consistent with management expectations. The full-cost method follows guidance provided in SEC Regulation S-X Rule 4-10, where impairment is determined by the “ceiling test,” whereby to the extent that such capitalized costs subject to amortization in the full-cost pool (net of accumulated depletion, depreciation and amortization, and related tax effects) exceed the present value (using a 10% discount rate) of estimated future net after-tax cash flows from proved oil and natural gas reserves, such excess costs are charged to expense.  Once incurred, an impairment of oil and natural gas properties is not reversible at a later date.  A ceiling test impairment could result in a significant loss for a reporting period; however, future depletion expense would be correspondingly reduced. Impairment of oil and natural gas properties is assessed on a quarterly basis in conjunction with the Company’s quarterly and annual SEC filings.  No ceiling test impairment was required during the quarters ended March 31, 2008 or 2007.

In accordance with SEC Staff Accounting Bulletin (“SAB”) No. 103, Update of Codification of Staff Accounting Bulletins , derivative instruments qualifying as cash flow hedges are to be included in the computation of limitation on capitalized costs.  Since January 1, 2006, the Company has not applied cash flow hedge accounting to any derivative contracts (see Note 8), therefore the ceiling tests at March 31, 2008 and 2007 were not impacted by the value of our derivatives.

Oil and natural gas properties are amortized based on a unit-of-production method using estimates of proved reserve quantities. Oil and natural gas liquids (“NGL”s) are converted to a gas equivalent basis (“Mcfe”) at the rate of one barrel equals six Mcf. In accordance with SAB No. 106, Interaction of Statement 143 and the Full Cost Rules, the amortizable base includes estimated future development and dismantlement costs, and restoration

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and abandonment costs, net of estimated salvage values. Investments in unproved properties are not amortized until proved reserves associated with the prospects can be determined or until impairment occurs. Unproved properties are evaluated quarterly, and as needed, for impairment on a property-by-property basis. If the results of an assessment indicate that an unproved property is impaired, the amount of impairment is added to the proved oil and natural gas property costs to be amortized. Oil and natural gas properties included costs of $32.1 million and $34.9 million at March 31, 2008 and December 31, 2007, respectively, related to unproved property, which were excluded from capitalized costs being amortized.

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.

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 in Arkansas. 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 $48,700 of this commitment through March 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. We currently have not recorded a liability for these commitments, but if the Company were  to cease drilling or otherwise decide there is no development potential in this area, it may not be able to meet the minimum physical delivery based on estimated future production and thus record a liability for the remaining amount of the commitment.

These contracts are not considered derivatives, but have been designated as annual sales contracts under Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended).

Accounts Receivable and Allowance for Doubtful Accounts - The Company routinely assesses the recoverability of all material trade and other receivables to determine its ability to collect the receivables in full. Accounts Receivable, Joint Interest Owners included an “allowance” for doubtful accounts of $3,200 at March 31, 2008 and December 31, 2007.

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

Asset Retirement Obligations – The Company records a liability for legal obligations associated with the retirement of tangible long-lived assets in the period in which they are incurred in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations. Under SFAS No. 143, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and gas properties is increased. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset. The changes to the Asset Retirement Obligations (“ARO”) for oil and natural gas properties and related equipment during the three months ended March 31, 2008 and 2007 are as follows:

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During the three months ended March 31, 2008, ARO liabilities were recorded for 32 new obligations and liabilities settled include three properties that were plugged and abandoned and 104 properties that were sold. We also recorded a net gain of approximately $9,400 related to ARO settlements.

Share-Based Compensation – The Company accounts for share-based compensation in accordance with the provisions of SFAS No. 123R, Share-Based Payment, which requires that the compensation cost relating to share-based payment transactions be recognized in financial statements. Share-based compensation for the three months ended March 31, 2008 was approximately $0.8 million, of which $0.7 million was included in general and administrative expenses (“G&A”) and $0.1 million was capitalized to oil and natural gas properties. Share-based compensation for the three months ended March 31, 2007 was approximately $0.7 million, of which approximately $0.5 million was included in general and administrative expenses (“G&A”) and $0.2 million was capitalized to oil and natural gas properties.

During the three months ended March 31, 2008, 1,600 restricted stock units (“RSUs”) were granted. At March 31, 2008, 560,750 RSUs were outstanding, all of which are classified as equity instruments.  No options were granted during the three months ended March 31, 2008, and at period end 643,600 vested unexercised options were outstanding.

Income Taxes - Effective January 1, 2007, the Company adopted FASB Interpretation No. 48 Accounting for Uncertainty in Income Taxes (an interpretation of FASB Statement No. 109) (“FIN 48”).  This interpretation clarified the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return.  FIN 48 also provides guidance on de-recognitions, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company also adopted FASB Staff Position (“FSP”) No. FIN 48-1, Definition of Settlement in FASB Interpretation No. 48 as of January 1, 2007.  FSP FIN 48-1 provides that a company’s tax position will be considered settled if the taxing authority has completed its examination, the company does not plan to appeal, and it is remote that the taxing authority would reexamine the tax position in the future (see Note 6).

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

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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 financial statements, but it did result in additional required disclosures as set forth in Note 9. 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 financial statements resulting from the adoption of SFAS No. 159.

Recent Accounting Pronouncements – In December 2007, the FASB issued SFAS No. 141(R), Business Combinations (“SFAS No. 141(R)”). SFAS No. 141(R) 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 revenue, not goodwill; changes the recognition timing for restructuring costs; and requires acquisition costs to be expensed as incurred. Adoption of SFAS No. 141(R) is required for combinations after December 15, 2008. Early adoption and retroactive application of SFAS No. 141(R) 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. 141(R) 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.

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.

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2.   LONG-TERM DEBT

On January 30, 2007, the Company entered into a Fourth Amended and Restated Credit Agreement (the “Agreement”) for a new Revolving Credit Facility with Union Bank of California (“UBOC”), as administrative agent and issuing lender, and the other lenders party thereto. Pursuant  to the Agreement, UBOC acts as the administrative agent for a senior, first lien secured borrowing base revolving credit facility (the “Revolving Facility”) in favor of the Company and certain of its wholly-owned subsidiaries in an amount equal to $750 million, of which only $300 million was available under the borrowing base at March 31, 2008. The Revolving Facility has a letter of credit sub-limit of $20 million.

The Revolving Facility matures on January 31, 2011 and bears interest at 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 March 31, 2008, the interest rates applied to the Company’s outstanding Prime and LIBOR borrowings were 5.50% and 6.99%, respectively.  As of March 31, 2008, $250 million in total borrowings were outstanding under the Revolving Facility. The Company’s available borrowing capacity under the Revolving Facility was $50 million at March 31, 2008. The borrowing base was reduced from $320 million to $300 million during the fourth quarter of 2007. In early May 2008, our Revolving Facility’s borrowing base was redetermined by our banks and set at $250 million, by which time the Company also repaid $5 million of outstanding borrowings leaving $5 million of availability at the time of this filing. The borrowing base is scheduled to be redetermined again on or before June 30, 2008.

The Revolving Facility is secured by substantially all of the Company’s assets. The Revolving Facility provides for certain restrictions, including, but not limited to, limitations on additional borrowings, sales of oil and natural gas properties or other collateral, and engaging in merger or consolidation transactions. The Revolving Facility restricts dividends and certain distributions of cash or properties and certain liens and also contains financial covenants including, without limitation, the following:

·                   An EBITDAX to interest expense ratio requires that as of the last day of each fiscal quarter the ratio of (a) Edge’s consolidated EBITDAX (defined as EBITDA plus similar non-cash items and exploration and abandonment expenses for such period) to (b) Edge’s consolidated interest expense, not be less than 2.5 to 1.0, calculated on a cumulative quarterly basis for the first 12 months after the closing of the Revolving Facility and then on a rolling four quarter basis.

·                   A current ratio requires that as of the last day of each fiscal quarter the ratio of Edge’s consolidated current assets to Edge’s consolidated current liabilities, as defined in the Revolving Facility, be at least 1.0 to 1.0.

·                   A maximum leverage ratio requires that as of the last day of each fiscal quarter the ratio of (a) Total Indebtedness (as defined in the Agreement) to (b) an amount equal to consolidated EBITDAX be not greater than 3.0 to 1.0, calculated on a cumulative quarterly basis for the first 12 months after the closing of the Revolving Facility and then on a rolling four quarter basis.

Consolidated EBITDAX is a component of negotiated covenants with our lender and is discussed here as part of the Company’s disclosure of its covenant obligations. 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 in control.  “Change in 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

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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.

3.   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 May 12, 2008, the Company had $500 million available under its shelf registration statement.

4.   PREFERRED STOCK

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

Dividends .  The Convertible Preferred Stock accumulates dividends at a rate of $2.875 for each share of Convertible Preferred Stock per year. Dividends are cumulative from the date of first issuance and, to the extent payment of dividends is not prohibited by the Company’s debt agreements, assets are legally available to pay dividends and the board of directors or an authorized committee of the board declares a dividend payable, the Company will pay dividends in cash, every quarter. The first payment was made on April 15, 2007.

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

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

Ranking .  Our Convertible Preferred Stock ranks:

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

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

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

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

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

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

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

Purchase upon fundamental change . If the Company becomes subject to a fundamental change (as defined 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 our debt.

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

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

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

2. consummation of any share exchange, consolidation or merger of the Company pursuant to which its common stock will be converted into cash, securities or other property or any sale, lease or other transfer in one transaction or a series of transactions of all or substantially all of the consolidated assets of the Company and its subsidiaries, taken as a whole, to any person other than one of its subsidiaries; provided, however, that a transaction where the holders of more than 50% of all classes of its common equity

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

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

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

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

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

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

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

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

·                   reclassify any of 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.

5.   EARNINGS PER SHARE

The Company accounts for earnings per share in accordance with SFAS No. 128, Earnings per Share , which establishes the requirements for presenting earnings per share (“EPS”).  SFAS No. 128 requires the presentation of “basic” and “diluted” EPS on the face of the 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 and warrants 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 three months ended March 31, 2008 and 2007, potential common shares are excluded in the computation of diluted EPS because it 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 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:

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(1)    In the calculation of diluted EPS for the quarter ended March 31, 2008, the 8.7 million shares of common stock resulting from an assumed conversion of the Company’s Convertible Preferred Stock and 69,531 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 quarter ended March 31, 2007, the 8.7 million shares of common stock resulting from an assumed conversion of the Company’s Convertible Preferred Stock and 303,552 equivalent shares of the Company’s restricted stock units and common stock options were excluded because the conversion would be anti-dilutive.

6.   INCOME TAXES

The Company accounts for income taxes under the provisions of SFAS No. 109, Accounting for Income Taxes , which provides for an asset and liability approach in accounting for income taxes.  Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences, using currently enacted tax laws, attributable to temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts calculated for income tax purposes.

The Company currently estimates that its effective tax rate for the year ending December 31, 2008 will be approximately 35%.  An income tax benefit of $8.6 million (34.83% of pre-tax income) was reported for the three months ended March 31, 2008.  An income tax benefit of $2.9 million (34.95% of pre-tax loss) was reported for the three months ended March 31, 2007. The Company’s income tax provision in 2008 is primarily non-cash as the Company has NOL carryforwards available that were generated from drilling activity.  Currently, the Company anticipates that it will incur federal alternative minimum tax for the year ended 2008. An overpayment of approximately $229,000 is anticipated from the prior tax year, resulting in no required payments at March 31, 2008.

The Company also accounts for income taxes under the provisions of FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in accordance with SFAS No. 109 , and FSP FIN 48-1, which 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. FIN 48 prescribes a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. FIN 48 also requires that the amount of interest expense to be recognized related to uncertain tax positions be computed by applying the applicable statutory rate of interest to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken in a tax return. The Company recognizes interest and penalties related to unrecognized tax benefits in tax expense. However, the Company has accrued no interest or

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penalties at March 31, 2008. The Company files income tax returns in the United States and various state jurisdictions. The Company’s tax returns for 2005 and 2006 remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed. The calculation of the net operating loss carryforwards from years prior to 2005 also remain open for examination.

7.   SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION AND NON-CASH INVESTING AND FINANCING ACTIVITIES

The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. A summary of non-cash investing and financing activities is presented below:

For the three months ended March 31, 2008 and 2007, the non-cash portion of Asset Retirement Costs was $0.7 million and $(0.9) million, respectively. Dividends declared but not yet paid were $2.1 million, of which $1.7 million was accrued at March 31, 2008, and for the same prior year period dividends declared but not yet paid were $1.7 million, of which $1.4 million was accrued at March 31, 2007. A supplemental disclosure of cash flow information is presented below:

8.   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 commodity 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 forecasted 2008 production and the impact of certain divestitures, both of which have reduced expected production as compared to that expected at the time the Company entered into the derivative contracts, the Company currently has approximately 110% and 150% of its anticipated 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 are, at the time of their execution, intended to be used for trading or speculative purposes, but may be deemed as such because of the decrease in the Company’s expected 2008 production. These derivative transactions are generally placed with major financial institutions that the Company believes are minimal credit risks. 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 monitors the Company’s policies and trades monthly.

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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 instrument contracts are recorded on the balance sheet at fair value and the cash flows resulting from settlement of derivative transactions which relate to economically hedging the Company’s physical production volumes are classified in operating activities on the statement of cash flows and the cash flows resulting from settlement of derivative transactions considered “overhedged” positions are classified in investing activities on the statement of cash flows. For those derivatives in which mark-to-market accounting treatment is applied, the changes in fair value are not deferred through other comprehensive income on the balance sheet. Rather they are immediately recorded in total revenue on the statement of operations. While the contract is outstanding, the unrealized gain or loss may increase or decrease until settlement of the contract depending on the fair value at the measurement dates. The Company evaluates the terms of new contracts entered into to determine whether cash flow hedge accounting treatment or mark-to-market accounting treatment will be applied. The Company has applied mark-to-market accounting treatment to all outstanding contracts since January 1, 2006.

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

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

(1)    The Company’s natural gas collars 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 collars 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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9.     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 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.

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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 March 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.

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

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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.

10.  DIVESTITURES

During the first quarter of 2008, the Company completed the sale of certain non-core assets, which included approximately 100 properties in Texas, to various buyers for aggregate proceeds of approximately $12.2 million.

11.  COMMITMENTS AND CONTINGENCIES

From time to time the Company is a party to various legal proceedings arising in the ordinary course of business.  While the outcome of lawsuits cannot be predicted with certainty, the Company is not currently a party to any proceeding that it believes, if determined in a manner adverse to the Company, could have a material adverse effect on its 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 Goliad County, Texas and failure and refusal to pay monies to Blake pursuant to such overriding royalty interests for wells completed on the leases. The plaintiffs seek relief of (1) specific performance of the alleged agreement, including granting of overriding royalty interests by the Company to Blake; (2) monetary damages for failure to grant the overriding royalty interests; (3) exemplary damages for his claims of business disparagement and slander; (4) monetary damages for tortuous 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 has served plaintiffs with discovery and has filed a counterclaim and an amended counterclaim joining various related entities that are controlled by plaintiffs.  In addition, plaintiffs have filed an amended complaint alleging claims of slander of title and tortuous interference related to its alleged right to receive an overriding royalty interest from a third party.  Plaintiffs currently have on file an amended motion for summary judgment, to which the Company has filed a response.  In addition, the Company has filed a motion for summary judgment on the plaintiffs’ case.  In December 2006, the court denied the Company’s motion for summary judgment.  The court has not ruled on Blake’s motion.  In November 2007, the Company filed a separate motion for summary judgment based on the statute of frauds; the court has not ruled on this separate motion.  The trial, originally scheduled to begin September 10, 2007, and reset for March 3, 2008, has been continued until August 20, 2008.  Discovery in the case has commenced and is continuing. The Company has responded 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 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 a vendor of the Company, Payzone Logging.   No specific amount of damages has been alleged to date; plaintiffs are asserting damages from loss of companionship, pecuniary loss, pain and mental anguish, loss of inheritance and funeral and burial expenses.  The Company may have insurance coverage for all or part of this claim.  The Company’s insurance carrier has retained

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local counsel to represent the Company in this matter.  The Company filed an answer on January 30, 2008 denying plaintiffs’ allegations and asserting defenses and trial has been set for February 16, 2009.  The Company has not established a reserve with respect to this claim and it is not possible to determine what, if any, the Company’s ultimate exposure might be in this matter.  The Company will continue to respond aggressively to this lawsuit, and believes that it has meritorious defenses.

Lexington Insurance Company v. Edge Petroleum Exploration Company, et al. - On March 13, 2008, Lexington Insurance Company (“Lexington”) filed a declaratory judgment action in the 125 ^th Judicial District Court of Harris County, Texas.  Lexington seeks a judgment that it is not obligated to pay any claims of the Company and the Sfondrini Partnerships (as defined below) in connection with a consolidated suit that Company and the Sfondrini Partnerships settled with the all of the plaintiffs in 2007.  The suit that was settled,   Wade and Joyce Montet, et al., v. Edge Petroleum Corp of Texas, et al., consolidated with Rolland L. Broussard, et al., v. Edge Petroleum Corp of Texas, et al ., and the settlement thereof, is described in detail in Item 3. Legal Proceedings of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.  In general, the action was a consolidated suit by mineral/royalty owners under two wells, who claimed that the third party operator of the wells had failed to “block squeeze” the sections of one of the wells, as a prudent operator, according to their allegations, would have done, to protect the gas reservoir from being flooded with water from adjacent underground formations, and was negligent in not creating a field-wide unit to protect their interests.  The Company and the Sfondrini Partnerships were defendants in the suit as working interest owners in the wells, owning 2.8% and 14.7%, respectively, at the time of the alleged acts or omissions.  In the case of the settlements with some, but not all, of the plaintiffs, two other insurers covered the settlement amounts in exchange for mutual releases.  The Company and the Sfondrini Partnerships bore the costs of the settlements with the remaining plaintiffs in accordance with their proportionate interests.  The Sfondrini Partnerships are partnerships that are directly or indirectly controlled by John Sfondrini, a director of the Company.  Vincent Andrews, also a director of the Company, owns a minority interest in the corporate general partner one of the partnerships.

Lexington asserts that it is not obligated to pay any claims of the Company and the Sfondrini Partnerships under its commercial, general liability insurance policy as related to the lawsuit that was settled because there was no “occurrence,” under the terms of their policy, of physical injury to or destruction of tangible property and other reasons.  The Company’s position is that the damages to the reservoir and attendant losses incurred by the defendants were losses covered by Lexington’s policy, for which Lexington is legally obligated to pay.  By agreement of the parties, an answer is due 30 days from notice of termination of settlement discussions.  Because the Company has already settled the underlying claims and has not recognized any amount for possible future recoveries against Lexington, it does not, in any event, expect the declaratory judgment action by Lexington to have a material adverse affect on the Company.

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

The following is Management’s Discussion and Analysis (“MD&A”) of significant factors that have affected certain aspects of our financial position and operating results during the periods included in the accompanying unaudited condensed consolidated financial statements. The following MD&A is intended to help the reader understand Edge Petroleum Corporation (“Edge”). This discussion should be read in conjunction with the accompanying unaudited condensed consolidated financial statements included elsewhere in this Form 10-Q and with MD&A of Financial Condition and Results of Operations and our audited consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2007 (“2007 Annual Report”) .

FORWARD LOOKING STATEMENTS

Certain of the statements contained in all parts of this document, including, but not limited to, those relating to our drilling plans (including scheduled and budgeted wells), the effect of changes in strategy and business discipline, future tax matters, our 3-D project portfolio, future general and administrative expenses on a per unit of production basis, changes in wells operated and reserves, future growth and expansion, future exploration, future seismic data (including timing and results), the ongoing assessment of strategic alternatives, expansion of operation, our ability to generate additional prospects, review of outside generated prospects and acquisitions, additional reserves and reserve increases, our ability to replace production and manage our asset base, enhancement of visualization and interpretation strengths, expansion and improvement of capabilities, integration of new technology into operations, credit facilities, redetermination of our borrowing base, attraction of new members to the technical team, future compensation programs, new focus on core areas, new prospects and drilling locations, new alliances, future capital expenditures (or funding thereof) and working capital, sufficiency of future working capital, borrowings and capital resources and liquidity, projected rates of return, retained earnings and dividend policies, projected cash flows from operations, future commodity price environment, expectation or timing of reaching payout, the outcome, effects or timing of any legal proceedings or contingencies, the impact of any change in accounting policies on our financial statements, the number, timing or results of any wells, the plans for timing, interpretation and results of new or existing seismic surveys or seismic data, future production or reserves, future acquisition of leases, lease options or other land rights, any other statements regarding future operations, financial results, opportunities, growth, business plans and strategy and other statements that are not historical facts are forward-looking statements. These forward-looking statements reflect our current view of future events and financial performance. When used in this document, the words “budgeted,” “anticipate,” “estimate,” “expect,” “may,” “project,” “believe,” “intend,” “plan,” “potential,” “forecast,” “might,” “predict,” “should” and similar expressions are intended to be among the expressions that identify forward-looking statements. These forward-looking statements speak only as of their dates and should not be unduly relied upon. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, or otherwise. Such statements involve risks and uncertainties, including, but not limited to, those set forth under “ITEM 1A. RISK FACTORS” of our 2007 Annual Report, the ongoing assessment of strategic alternatives, and other factors detailed in this document and our other filings with the Securities and Exchange Commission (the “SEC”). Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties.

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 began a shift in strategy from pure exploration, which focused more on prospect generation, to our current strategy which focuses on a balanced program of exploration, exploitation and development and acquisition of oil and natural gas properties. We generate revenues, income and cash flows by producing and marketing oil and natural gas produced from our oil and natural gas properties. We make significant capital expenditures in our exploration, development, and production activities that allow us to

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continue generating revenue, income and cash flows. We have also spent considerable efforts on acquisitions, including both corporate and asset acquisitions, which have contributed to our growth in recent years.

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

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

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

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

·                   Assessment of Strategic Alternatives – information about our strategic assessment process.

·                   Outlook – discussion relating to management’s outlook to the future of our business.

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

·                   Results of Operations – an analysis of our 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.

·                   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.

Industry and Economic Factors

In managing our business, we must deal with many factors inherent in our industry.  First and foremost is the fluctuation of oil and natural gas prices.  Historically, oil and natural gas markets have been cyclical and volatile, which makes future price movements difficult to predict.  While our revenues are a function of both production and prices, wide swings in commodity prices have most often had the greatest impact on our results of operations. We have little ability to predict those prices or to control them without losing some advantage of the upside potential.

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.

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

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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.

The oil and gas industry is highly competitive. We compete with major and diversified energy companies, independent oil and gas businesses and individual operators in 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.

Approach to the Business

Profitable growth of our business will largely depend upon our ability to successfully find and develop new proved reserves of oil and natural gas in a cost-effective manner.  In order to achieve an overall acceptable rate of growth, we seek to maintain a prudent blend of low, moderate and higher risk exploration and development projects.  We have chosen to seek geologic and geographic diversification by operating in multiple basins in order to mitigate risk in our operations. In recent years, we have also made selected acquisitions of oil and natural gas properties to augment our growth and provide future drilling opportunities.

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 have reduced expected production as compared to that expected at the time we entered into the derivative contracts, we currently have approximately 110% and 150% of our anticipated 2008 natural gas and crude oil production, respectively, covered by derivative contracts. This overhedged position exposes us to greater risk of commodity price increases because we will not have the physical production cash inflows to offset any potential losses incurred on the portion of the contracts that are overhedged. As of March 31, 2008, we also had derivative contracts in place for a portion of our expected 2009 oil and natural gas production.

Generally, our goal is 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 ongoing strategic assessment process (see discussion below), our Board has approved an interim capital expenditure budget for 2008 of approximately $50 to $60 million, while we continue to assess the potential sale or merger of the Company. Based on current expectations for production volumes and commodity prices, we expect to fund those capital expenditures from internally generated cash from operating activities supplemented by modest borrowings on our credit facility. Any decision to expand our drilling program will depend in large part on the developments and results of our strategic assessment process that is currently underway (see “Outlook” section below). Our long-term debt balance as of March 31, 2008 was $250 million and our debt-to-total capital ratio was 37.5%. In early May 2008, our Revolving Facility’s borrowing base was redetermined by our banks and set at $250 million. It is scheduled to be redetermined again on or before June 30, 2008. As of May 12, 2008, we had unused borrowing capacity of $5 million.

Acquisitions and Divestitures

Acquisitions - We have become increasingly active in acquisitions in recent years. 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 acquiring an entire field of wells or a company. Unlike drilling capital, which is planned and budgeted, acquisition capital is neither budgeted nor allocated, because the specific timing or size of acquisitions cannot be predicted.  Any such

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acquisition could involve the payment by us of a substantial amount of cash or the issuance of a substantial number of additional shares or other securities. In today’s high-price environment, where production is providing greater cash flow and earnings to most companies in our industry, identifying quality opportunities is difficult.

Divestitures - We regularly review our asset base for the purpose of identifying non-core assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. While we generally do not dispose of assets solely for the purpose of reducing debt, such dispositions can have the result of furthering our objective of financial flexibility through reduced debt levels. During the first quarter of 2008, we completed the sale of certain working interests in approximately 100 properties located in Texas to various buyers for aggregate proceeds of approximately $12.2 million.

Assessment of 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 assessment process, which includes a thorough review and assessment of our strengths and weaknesses, competitive position and asset base, reporting that after careful analysis, management and our Board of Directors believed that the best route to maximizing stockholder value at that time was to focus on an assessment of a potential merger or sale of Edge. That process is ongoing.  A decision on any particular course of action has not been made and there can be no assurance that our Board of Directors will authorize any transaction. While that process is continuing, we intend to operate Edge in a manner designed to capture the most value possible for our stockholders.

Outlook

·                   During the three months ended March 31, 2008, we drilled 8 wells, all apparent successes. Given the backdrop of the ongoing strategic assessment process, we are operating under an interim capital spending budget while we continue to assess the potential merger or sale of the Company. This interim program, which could be supplemented quickly, calls for the drilling of 18 to 22 wells (7 to 9, net) during 2008, primarily in south Texas, and to a lesser extent in southeast New Mexico, and complemented by selected expenditures for land and seismic. The interim program provides for total capital spending in the range of $50 to $60 million.

·                   During the first quarter of 2008, we completed the sale of some non-core properties to various buyers for aggregate proceeds of approximately $12.2 million. We completed another small sale of non-core assets during the second quarter of 2008 for proceeds of approximately $5.1 million received in April 2008. The properties sold consist of various working interests in approximately 100 wells and related equipment and gathering lines located in Texas. We expect to close another small sale later in the second quarter.

·                   We apply mark-to-market accounting treatment to our outstanding derivative contracts, rather than cash flow hedge accounting treatment, and therefore significant volatility from the changes in fair value of those outstanding contracts have impacted our earnings in 2008 (see Note 8 to our consolidated financial statements). See “Approach to the Business” above for information regarding our current derivatives position in light of recent changes in expected production and dispositions.

             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 strategic assessment process, access to capital, the acquisitions market and factors referred to in “Forward Looking Statements.”

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, contingent assets and liabilities and the related disclosures in the accompanying financial statements.  Changes in these estimates and assumptions could materially affect our financial position, results of operations or cash flows. Management considers an accounting estimate to be critical if:

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

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

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

Nature of Critical Estimate Item: Oil and Natural Gas Reserves - Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment, as well as prices and cost levels at that point in time. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements.

Assumptions/Approach Used: Units-of-production method to amortize our oil and natural gas properties - The quantity of reserves is used in calculating depletion expense and could significantly impact our depletion expense.

“Ceiling” Test - The full-cost method of accounting for oil and natural gas properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full-cost ceiling test. The ceiling is the discounted present value of our estimated total proved reserves (using a 10% discount rate) adjusted for taxes and the impact of cash flow hedges on pricing, if cash flow hedge accounting is applied. The ceiling test calculation dictates that prices and costs in effect as of the last day of the period are to be used in calculating the discounted present value of our estimated total proved reserves. However, if prices increase subsequent to the balance sheet date, but before the filing date, SEC guidelines allow a company to use the subsequent date’s higher prices in calculating the full-cost ceiling. We made this election for the third and fourth quarters of 2007. To the extent that our capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense. Once incurred, this impairment of oil and natural gas properties is not reversible at a later date even if oil and natural gas prices increase. A ceiling test impairment could result in a significant loss for a reporting period; however, future depletion expense would be correspondingly reduced. Our average oil and natural gas prices at the balance sheet date of March 31, 2008 were $101.58 per barrel and $9.37 per MMBtu. As a result, no ceiling test impairment was required for the three months ended March 31, 2008. No such impairment was required in the three months ended March 31, 2007.

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” limitation test - Factors that contribute to a ceiling test impairment include the price used to calculate the reserve limitation threshold and reserve quantities. A reduction in prices at a measurement date could trigger a full-cost ceiling impairment. We had a cushion of $75.9 million, net of tax, at March 31, 2008. A 10% increase or decrease in prices would have increased or decreased our cushion (i.e. the excess of the ceiling over our capitalized costs) by approximately 80%, 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 March 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, the cushion at March 31, 2008 would have been 16% lower. A 10% increase or decrease in reserve volume would have increased or decreased the cushion calculated at March 31, 2008 by approximately 60%.

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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. Prior to the adoption of Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations, 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 which 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 upon acquisition of the asset, adjust those costs for inflation to the forecast abandonment date, discount that amount using a credit-adjusted-risk-free rate back to the date we acquired the asset or obligation to retire the asset and record an ARO liability in that amount with a corresponding addition to our asset value. When new obligations are incurred, i.e. a new well is drilled or acquired, we add to the ARO liability. Should either the estimated life or the estimated abandonment costs of a property change upon our quarterly review, our estimate must be revised. When well obligations are relieved by sale of the property or plugging and abandoning the well, the related estimated liability and asset costs are removed from our balance sheet and replaced by the costs actually spent on retiring the asset.

Estimating the future asset removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future, and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the estimate of the present value calculation of our AROs are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted-risk-free-rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments.

Assumptions/Approach Used:   Since there are so many variables in estimating AROs, we attempt to limit the impact of management’s judgment on certain of these variables by using input of qualified third parties. We engage independent engineering firms to evaluate our properties annually. We use the remaining estimated useful life from the period-end reserve reports prepared by our independent reserve engineers in estimating when abandonment could be expected for each property. We utilize a three-year average rate for inflation to diminish any significant volatility that may be present in the short term. We have developed a standard cost estimate based on historical costs, industry quotes and depth of wells. Unless we expect a well’s plugging to be significantly different than a normal abandonment, we use this estimate.

Effect if Different Assumptions Used: We expect to see our calculations 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. The resulting estimate, after application of a discount factor and some significant calculations, could differ from actual results, despite all our efforts to make an accurate estimate.

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

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accounting standards, it is reduced by a valuation allowance to remove the benefit of those NOL carryforwards from our financial statements. Additionally, in accordance with Financial Accounting Standards Board (“FASB”) Interpretation 48, Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109 (“FIN 48”) we have recorded a liability of $0.5 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 the financial statements.  The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.

Assumptions/Approach Used: Numerous judgments and assumptions are inherent in the determination of future taxable income and tax return filing positions that we take, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). We are not currently required to pay any federal income taxes because of an anticipated loss generated during the current year.

Effect if Different Assumptions Used: Our in-house tax department, along with consultation from an independent public accounting firm used in tax consultation, 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 record a valuation allowance to remove the benefit of those NOL carryforwards from our financial statements. 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.

Nature of Critical Estimate Item: Derivative and Hedging Activities - Due to the instability of oil and natural gas prices, we may enter into, from time to time, price-risk management transactions (e.g. swaps, collars and floors) related to our expected oil and natural gas production to seek to achieve a more predictable cash flow, as well as to reduce exposure from commodity price fluctuations. While these transactions are intended to be economic hedges of price risk, different accounting treatment may apply depending on if they qualify for cash flow hedge accounting. In accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended), all derivatives, other than those that meet the normal purchases and sales exception, are recorded on the balance sheet at fair value.

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

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

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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 derivatives. 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 total revenue on the statement of operations rather than deferred in OCI on the balance sheet.

Effect if Different Assumptions Used: At March 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 $3.6 million. Had we applied cash flow hedge accounting treatment to all of our derivative contracts outstanding at March 31, 2008, our net loss to common stockholders for the three months would have been approximately $1.7 million, or $0.06 per basic and diluted loss per share, assuming that all hedges were fully effective.

Results of Operations

This section includes discussion of our results of operations for the three months ended March 31, 2008 as compared to the same period of the prior year. We are an independent oil and natural gas company engaged in the exploration, development, acquisition and production of crude oil and natural gas properties in the United States. Our resources and assets are managed and our results reported as one operating segment. We conduct our operations primarily along the onshore United States Gulf Coast, with our primary emphasis in Texas, Mississippi, New Mexico and Louisiana.

First Quarter 2008 Compared to the First Quarter 2007

Revenue and Production

Total revenue decreased 23% from the first quarter of 2007 to the comparable 2008 period. Excluding the effects of derivative activity, revenues increased 20% from the first quarter of 2007 to the comparable 2008 period. For the three months ended March 31, 2008 and 2007, our product mix contributed the following percentages of revenues and production volumes: