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**UNITEDSTATESSECURITIES AND EXCHANGE COMMISSION****Washington, D.C. 20549**

**FORM10-Q**
| **ý**                                        | **QUARTERLY REPORT  UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**  |
|---------------------------------------------------|-----------------------------------------------------------------------------------------|
|                                              |
| **For  the quarterly period ended June 30, 2001** |
|                                              |
| **OR**                                            |
|                                              |
| **o**                                             | **TRANSITION REPORT  UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934** |

**For the transition period from._________ to _________**

**Commission file number 0-22149**

**EDGEPETROLEUM CORPORATION******(Exact name ofregistrant as specified in its charter)

 

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

**Texaco Heritage Plaza1111 Bagby, Suite 2100Houston, Texas 77002**(Address of principal executive offices)

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

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

Yesý  No o

             Indicatethe number of shares outstanding of each of the issuer’s classes of commonequity, as of the latest practicable date.

| Class        | Outstanding at August  10, 2001 |
|--------------|---------------------------------|
|              |                                 |
| Common Stock | 9,304,046                       |

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** **

**PART I. FINANCIAL INFORMATION**

**Item 1. Financial Statements**
|                             |
|----------------------------------|
| **EDGE  PETROLEUM CORPORATION**  |
| **CONSOLIDATED  BALANCE SHEETS** |
| ****                             |

 
|                                                                                                   | June  30,   2001                                                                                                                                                                  |       | December  31,   2000 |       |
|--------------------------------------------------------------------------------------------------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------|------------|
|                                                                                                   |                                                                                                                                                                                   |       |                      |       |
|                                                                                                   | (Unaudited)                                                                                                                                                                       |       |                 |       |
| **ASSETS**                                                                                             |                                                                                                                                                                              |       |                 |       |
| CURRENT ASSETS:                                                                                        |                                                                                                                                                                              |       |                 |       |
|                                                                                                   | Cash and cash  equivalents                                                                                                                                                        | $          | 6,356,706            |       | $ | 247,981 |   |
|                                                                                                   | Accounts receivable,  trade, net of allowance of $300,000 and $0 at June 30, 2001 and  December 31, 2000, respectively                                                       | 4,489,968  |                 | 8,752,871  |   |
|                                                                                                   | Accounts receivable,  joint interest owners, net of allowance of $163,000 at each of June 30, 2001  and December 31, 2000                                                         | 388,684    |                 | 369,524    |   |
|                                                                                                   | Accounts receivable,  related parties                                                                                                                                             | 1,295      |                 | 22,410     |   |
|                                                                                                   | Other current assets                                                                                                                                                              | 783,083    |                 | 298,973    |   |
|                                                                                                   |                                                                                                                                                                                   |       |                      |       |
|                                                                                                   | Total current assets                                                                                                                                                              | 12,019,736 |                 | 9,691,759  |   |
| PROPERTY AND  EQUIPMENT, Net – full cost method of accounting for oil and natural gas  properties | 51,015,322                                                                                                                                                                        |       | 47,242,409           |       |
| OTHER ASSETS                                                                                           | 329,788                                                                                                                                                                           |       | 7,788                |       |
|                                                                                                   |                                                                                                                                                                                   |       |                      |       |
| TOTAL ASSETS                                                                                           | $                                                                                                                                                                                 | 63,364,846 |                 | $          | 56,941,956 |   |
|                                                                                                   |                                                                                                                                                                                   |       |                      |       |
| **LIABILITIES AND STOCKHOLDERS’  EQUITY**                                                         |                                                                                                                                                                              |       |                 |       |
| CURRENT LIABILITIES:                                                                                   |                                                                                                                                                                              |       |                 |       |
|                                                                                                   | Accounts payable,  trade                                                                                                                                                          | $          | 578,983              |       | $ | 1,277,440 |   |
|                                                                                                   | Accrued liabilities                                                                                                                                                               | 2,689,229  |                 | 2,484,865  |   |
|                                                                                                   | Accrued interest  payable                                                                                                                                                         | --         |                 | 50,385     |   |
|                                                                                                   | Current portion of  long-term debt                                                                                                                                                | --         |                 | 3,000,000  |   |
|                                                                                                   |                                                                                                                                                                                   |       |                      |       |
|                                                                                                   | Total current liabilities                                                                                                                                                         | 3,268,212  |                 | 6,812,690  |   |
| DEFERRED INCOME TAX                                                                                    | 781,595                                                                                                                                                                           |       | --                   |       |
| LONG-TERM DEBT                                                                                         | --                                                                                                                                                                                |       | --                   |       |
|                                                                                                   |                                                                                                                                                                                   |       |                      |       |
|                                                                                                   | Total liabilities                                                                                                                                                                 | 4,049,807  |                 | 6,812,690  |   |
|                                                                                                   |                                                                                                                                                                                   |       |                      |       |
| COMMITMENTS AND  CONTINGENCIES                                                                         |                                                                                                                                                                              |       |                 |       |
|                                                                                                   |                                                                                                                                                                              |       |                 |       |
| STOCKHOLDERS’ EQUITY                                                                              |                                                                                                                                                                              |       |                 |       |
|                                                                                                   | Preferred stock, $0.01  par value; 5,000,000 shares authorized; none issued and outstanding                                                                                       | --         |                 | --         |   |
|                                                                                                   | Common stock, $0.01  par value; 25,000,000 shares authorized; 9,304,139 shares and 9,186,071  shares issued and outstanding at June 30, 2001 and December 31, 2000,  respectively | 93,041     |                 | 91,861     |   |
|                                                                                                   | Additional paid-in  capital                                                                                                                                                       | 55,938,003 |                 | 56,247,130 |   |
|                                                                                                   | Retained earnings  (accumulated deficit)                                                                                                                                          | 3,296,783  |                 | (6,209,725 | ) |
|                                                                                                   | Accumulated other  comprehensive loss                                                                                                                                             | (12,788    | )                    | --         |   |
|                                                                                                   |                                                                                                                                                                                   |       |                      |       |
|                                                                                                   | Total stockholders’  equity                                                                                                                                                  | 59,315,039 |                 | 50,129,266 |   |
|                                                                                                   |                                                                                                                                                                                   |       |                      |       |
| TOTAL LIABILITIES AND  STOCKHOLDERS’ EQUITY                                                       | $                                                                                                                                                                                 | 63,364,846 |                 | $          | 56,941,956 |   |
|                                                                                                   |                                                                                                                                                                                   |       |                      |       |
|                                                                                                        |                                                                                                                                                                                   |            |                      |            |  |  |  |  |

 

Seeaccompanying notes to consolidated financial statements.**EDGE  PETROLEUM CORPORATION****CONSOLIDATED  STATEMENTS OF OPERATIONS (Unaudited)******
 
 Three  Months Ended June 30, Six  Months Ended June 30,     2001 2000 2001 2000      OIL AND NATURAL GAS  REVENUE$8,045,144 $4,682,839 $19,568,215 $8,493,760          OPERATING EXPENSES:         Lifting costs695,416 572,153 1,303,326 1,011,962  Severance and ad  valorem taxes629,407 304,143 1,543,734 610,792  Depletion,  depreciation and amortization2,464,897 2,190,510 4,463,556 3,977,488  General and  administrative expenses1,410,128 1,011,158 2,638,469 1,889,937  Deferred compensation  expense10,409 -- (698,748)--  Unearned compensation  expense-- 8,589 -- 17,178       Total operating  expenses5,210,257 4,086,553 9,250,337 7,507,357      OPERATING INCOME2,834,887 596,286 10,317,878 986,403          OTHER INCOME AND  EXPENSE:         Loss on sale of  investment in Frontera-- (354,733)-- (354,733) Interest income55,928 13,637 78,829 26,870  Interest expense and  amortization of deferred loan costs(74,899)(46,599)(108,604)(90,678)     INCOME BEFORE INCOME  TAXES2,815,916 208,591 10,288,103 567,862 INCOME TAX BENEFIT  (EXPENSE)240,076 -- (781,595)--      NET INCOME$3,055,992 $208,591 $9,506,508 $567,862      BASIC EARNINGS PER  SHARE$0.33 $0.02 $1.03 $0.06      DILUTED EARNINGS PER  SHARE$0.31 $0.02 $0.97 $0.06      BASIC WEIGHTED AVERAGE  NUMBER OF COMMON SHARES OUTSTANDING9,289,027 9,179,309 9,256,680 9,178,407      DILUTED WEIGHTED  AVERAGE NUMBER OF COMMON SHARES OUTSTANDING9,867,502 9,334,381 9,834,664 9,284,146      
Seeaccompanying notes to consolidated financial statements.**EDGE  PETROLEUM CORPORATION****CONSOLIDATED  STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)******
 
 Common  Stock                    Shares Amount Additional  Paid-in Capital Retained  Earnings (Accumulated Deficit) Accumulated  Other Comprehensive Loss Total  Stockholders’ Equity        BALANCE, JANUARY 1,  20019,186,071 $91,861 $56,247,130 $(6,209,725)$-- $50,129,266 Exercise of stock  options75,965 759 390,042     390,801 Issuance of stock42,103 421 (421)    -- Deferred compensation  expense    (698,748)    (698,748)Transition adjustment        (1,137,221)(1,137,221)Amortization of  hedging loss        924,332 924,332 Change in valuation of  hedge loss        200,101 200,101 Net income      9,506,508   9,506,508        BALANCE, JUNE 30, 20019,304,139 $93,041 $55,938,003 $3,296,783 $(12,788)$59,315,039        
Seeaccompanying notes to consolidated financial statements.**EDGE  PETROLEUM CORPORATION****CONSOLIDATED  STATEMENTS OF CASH FLOWS (Unaudited)******
 
 Six  Months Ended June 30,    2001 2000    **CASH FLOWS FROM OPERATING  ACTIVITIES:** ** ** ** **Net income$9,506,508 $567,862 Adjustments to  reconcile net income to net cash provided by operating activities:     Deferred income taxes781,595 --  Depletion,  depreciation and amortization4,463,556 3,977,488  Bad debt expense300,000 --  Amortization of  deferred loan costs50,710 --  Deferred loss from  derivative activity(12,788)--  Deferred compensation(698,748)--  Unearned compensation  expense-- 17,178  Loss on sale of  investment to Frontera-- 354,733 Changes in assets and  liabilities:     (Increase) decrease in  accounts receivable, trade3,962,903 (800,125) (Increase) decrease in  accounts receivable, joint interest owners(19,160)881,541  Decrease in accounts  receivable, related parties21,115 22,341  Increase in other  assets(849,151)(25,959) Decrease in accounts  payable, trade(698,457)(421,969) Increase (decrease) in  accrued liabilities204,364 (2,287,562) Decrease in accrued  interest payable(50,385)--     Net cash provided by  operating activities16,962,062 2,285,528    **CASH FLOWS FROM INVESTING  ACTIVITIES:**     Oil and natural gas  property and equipment purchases(8,236,469)(3,498,572) Proceeds from the sale  of oil and natural gas properties and prospects-- 1,763,044  Proceeds from the sale  of investment in Frontera-- 1,600,000     Net cash used in  investing activities(8,236,469)(135,528)   **CASH FLOWS FROM FINANCING  ACTIVITIES:**     Borrowings from  long-term debt1,000,000 850,000  Payments of long-term  debt(4,000,000)(3,000,000) Net proceeds from  issuance of common stock390,801 --  Other(7,669)--     Net cash used in  financing activities(2,616,868)(2,150,000)   **NET INCREASE IN CASH AND CASH  EQUIVALENTS**6,108,725 -- **CASH AND CASH EQUIVALENTS,  BEGINNING OF PERIOD**247,981 --    **CASH AND CASH EQUIVALENTS,  END OF PERIOD**$6,356,706 $--    
Seeaccompanying notes to consolidated financial statements.
**EDGE  PETROLEUM CORPORATION****NOTES  TO THE CONSOLIDATED FINANCIAL STATEMENTS******
**1.          SUMMARY OFSIGNIFICANT ACCOUNTING POLICIES**

             Thefinancial statements included herein have been prepared by Edge PetroleumCorporation, a Delaware corporation (“we”, “our”, “us” or the “Company”),without audit pursuant to the rules and regulations of the Securities andExchange Commission, and reflect all adjustments which are, in the opinion ofmanagement, necessary to present a fair statement of the results for theinterim periods on a basis consistent with the annual audited consolidatedfinancial statements.  All suchadjustments are of a normal recurring nature. The results of operations for the interim periods are not necessarilyindicative of the results to be expected for an entire year.  Certain information, accounting policies andfootnote disclosures normally included in financial statements prepared inaccordance with accounting principles generally accepted in the United Statesof America have been omitted pursuant to such rules and regulations, althoughwe believe that the disclosures are adequate to make the information presentednot misleading. These financial statements should be read in conjunction withour audited consolidated financial statements included in our Annual Report onForm 10-K for the year ended December 31, 2000.

             *Concentrationof Credit Risk* – Substantially all of the Company’s accountsreceivable result from oil and natural gas sales or joint interest billings tothird parties in the oil and natural gas industry.  This concentration of customers and joint interest owners mayimpact the Company’s overall credit risk in that these entities may besimilarly affected by changes in economic and other conditions.  Historically, the Company has notexperienced significant credit losses on such receivables.  In July 2001, the Company was notified thata purchaser had not made payment for May and June production.  As a result, the Company reserved $300,000of bad debt expense in its results for the six months ended June 30, 2001 dueto the uncertainty of collecting from this purchaser.

             *Reclassifications* - Certain prior yearbalances have been reclassified to conform to current year presentation.

**Accounting Pronouncements**

             ***Derivatives*** – Weadopted Statement of Financial Accounting Standards No. 133, “Accounting forDerivative Instruments and Hedging Activities” (“SFAS 133”) effective January1, 2001.  The statement, as amended,requires that all derivatives be recognized as either assets or liabilities andmeasured at fair value, and changes in the fair value of derivatives bereported in current earnings, unless the derivative is designated and effectiveas a hedge.  If the intended use of thederivative is to hedge the exposure to changes in the fair value of an asset, aliability or firm commitment, then the changes in the fair value of thederivative instrument will generally be offset in the income statement by thechange in the item’s fair value. However, if the intended use of the derivative is to hedge the exposureto variability in expected future cash flows then the changes in fair value ofthe derivative instrument will generally be reported in Other ComprehensiveIncome (“OCI”).  The gains and losses onthe derivative instrument that are reported in OCI will be reclassified toearnings in the period in which earnings are impacted by the hedged item.

             Wewill account for our natural gas and crude oil hedge derivative instruments ascash flow hedges under SFAS 133. Although the fair value of our derivative instruments fluctuates daily,as of January 1, 2001, the fair value of the our natural gas hedge derivativeinstrument was approximately ($1.1) million, which was recorded in theConsolidated Balance Sheet on January 1, 2001. The ($1.1) million was recorded as a liability on our balance sheet aspart of the transition adjustment related to our adoption of SFAS 133.  The offset to this balance sheet adjustmentwas a decrease to “Accumulated Other Comprehensive Income”, a component ofstockholders’ equity. In early January, we closed out of our hedge obligationfor the period from February 1, 2001 to December 31, 2001.  As a result, we recorded a loss on theJanuary hedge of $389,360 and are amortizing the close out cost of $547,760based on the forward pricing curve at the time of the close out in accordancewith SFAS 133.  Included in earnings forthe first half of 2001 is a charge of $924,332 representing the loss in Januaryand the amortized portion of the close out cost as of June 30, 2001.  The unamortized balance of the close outcost of $12,788 is included in stockholders’ equity as accumulated othercomprehensive loss.  As of June 30,2001, we were not a party to any hedging activity.
             OnJune 29, 2001, the FASB approved its proposed SFAS No. 141, ("FAS141")  "BusinessCombinations," and SFAS No. 142 ("FAS 142"), "Goodwill andOther Intangible Assets."   UnderFAS 141, all business combinations should be accounted for using the purchasemethod of accounting; use of the pooling-of-interests method is prohibited. Theprovisions of the statement will apply to all business combinations initiatedafter June 30, 2001.

             FAS142 will apply to all acquired intangible assets whether acquired singly, aspart of a group, or in a business combination. The statement will supersedeAccounting Principals Board, ("APB"), Opinion No. 17,"Intangible Assets," and will carry forward provisions in APB OpinionNo.17 related to internally developed intangible assets. Adoption of FAS 142will result in ceasing amortization of goodwill. All of the provisions of thestatement should be applied in fiscal years beginning after December 15, 2001to all goodwill and other intangible assets recognized in an entity's statementof financial position at that date, regardless of when those assets wereinitially recognized.

             TheCompany does not expect the adoption of these standards to have a materialeffect on its consolidated financial statements.

**2.          LONG TERMDEBT**

             Duringthe first quarter of 2001, we repaid all amounts borrowed under our creditfacility (the “Credit Facility”) and as of June 30, 2001 no borrowings wereoutstanding. Future borrowings under the Credit Facility, if any, will bearinterest at a rate equal to prime plus 0.50% or LIBOR plus 2.75%.  The Credit Facility matures October 2, 2002and is secured by substantially all of our assets.

             Originallythe borrowing base under the Credit Facility was $5 million and was subject toautomatic reductions at a rate of $300,000 per month beginning February 28,2001.  In March 2001, the CreditFacility was amended to increase the borrowing base to $14 million, and toeliminate the $300,000 per month automatic reduction.  The borrowing base will be redetermined on a semi-annualbasis.  The Company expects theborrowing base to be re-determined in the third quarter of 2001.

             TheCredit Facility provides for certain restrictions, including but not limitedto, limitations on additional borrowings and issues of capital stock, sales ofoil and natural gas properties or other collateral, and engaging in merger orconsolidation transactions. The Credit Facility also prohibits dividends andcertain distributions of cash or properties and certain liens.  The Credit Facility also contains certainfinancial covenants. The EBITDA to Interest Expense Ratio requires that (a)consolidated EBITDA, as defined in the agreement, of the Company for the fourfiscal quarters then ended to (b) the consolidated interest expense of theCompany for the four fiscal quarters then ended, to not be less than 3.5 to1.0.  The Working Capital ratio requiresthat the amount of the Company’s consolidated current assets less itsconsolidated liabilities, as defined in the agreement, be at least $1.0million.  The Allowable Expenses ratiorequires that (a) the aggregate amount of the Company’s year to dateconsolidated general and administrative expenses for the period from January 1of such year through the fiscal quarter then ended to (b) the Company’s year todate consolidated oil and gas revenue, net of hedging activity, for the periodfrom January 1 of such year through the fiscal quarter then ended, to be lessthan .40 to 1.0.  At June 30, 2001, theCompany was in compliance with the above mentioned covenants.

**3.          EARNINGS PERSHARE**

             Weaccount for earnings per share in accordance with Statement of FinancialAccounting Standards No. 128 – “Earnings per Share,”  (“SFAS No. 128”) which establishes the requirements forpresenting earnings per share (“EPS”). SFAS No. 128 requires the presentation of “basic” and “diluted” EPS onthe face of the income statement.  Basicearnings per common share amounts are calculated using the average number ofcommon shares outstanding during each period. Diluted earnings per share assumes the exercise of all stock options andwarrants, having exercise prices less than the average market price of thecommon stock during the periods, using the treasury stock method.
             Thefollowing is presented as a reconciliation of the numerators and denominatorsof basic and diluted earnings per share computations, in accordance with SFASNo. 128.
 Three  Months Ended June 30, 2001 Three  Months Ended June 30, 2000     Income  (Numerator) Shares  (Denominator) Per  Share Amount Income  (Numerator) Shares  (Denominator) Per  Share Amount        **Basic EPS**            Income available to  common stockholders$3,055,992 9,289,027 $0.33 $208,591 9,179,309 $0.02 Effect of Dilutive  Securities:             Restricted stock  195,384 (0.01)  153,278 --  Common stock options  252,680 (0.01)  1,794    Warrants  130,411 --   -- --        **Diluted EPS**            Income available to  common stockholders$3,055,992 9,867,502 $0.31 $208,591 9,334,381 $0.02        
 
 Six  Months Ended June 30, 2001 Six  Months Ended June 30, 2000     Income  (Numerator) Shares  (Denominator) Per  Share Amount Income  (Numerator) Shares  (Denominator) Per  Share Amount        **Basic EPS**            Income available to  common stockholders$9,506,508 9,256,680 $1.03 $567,862 9,178,407 $0.06 Effect of Dilutive  Securities:             Restricted stock  163,654 (0.02)  103,227 --  Common stock options  273,265 (0.03)  2,512    Warrants  141,065 (0.01)  -- --        **Diluted EPS**            Income available to  common stockholders$9,506,508 9,834,664 $0.97 $567,862 9,284,146 $0.06        
**4.          INCOME TAXES**

             Weaccount for income taxes under the provisions of Statement of FinancialAccounting Standards No. 109 – “Accounting for Income Taxes,” (“SFAS No. 109”)which provides for an asset and liability approach in accounting for incometaxes.  Under this approach, deferredtax assets and liabilities are recognized based on anticipated future taxconsequences, using currently enacted tax laws, attributable to differencesbetween financial statement carrying amounts of assets and liabilities andtheir respective tax bases.  Due to theuncertainty as to whether we would be profitable in the future, an allowancewas provided to offset the tax benefits of certain tax assets.
             Basedon our current expectation of net income for the year ended December 31, 2001,we anticipate utilizing all of our available net tax assets during 2001.  Our annual effective tax rate is estimatedat approximately 8% at June 30, 2001. As a result, a provision for income tax expense of $781,595, or $0.08per share was included in our results for the six months ended June 30,2001.  In addition, we are now payingestimated alternative minimum tax payments resulting in a deferred tax asset of$322,000 at June 30, 2001. No income tax expense was recorded for the six-monthperiod ended June 30, 2000 as we had utilized the benefit of net operating losscarry-forwards to offset taxable income.

             Thedifference between the statutory federal income taxes calculated using afederal tax rate of 35% and our effective tax rate as of June 30, 2001 and 2000are summarized as follows:
 Six  Months Ended June 30,    2001 2000    Statutory federal  income taxes$3,600,836 $198,752      Permanent differences:     Expense not deductible  for tax purposes12,014 6,321  Change in valuation  allowance(2,831,255)(205,073)   Income tax expense$781,595 $--    
**5.          EQUITY**

             Weaccount for Stock Based Compensation in accordance with Statement of FinancialAccounting Standards No. 123 - “Accounting for Stock Based Compensation,”(“SFAS No. 123”).  Under SFAS No. 123,we are permitted to either record expense for stock options and other employeecompensation plans based on their fair value at the date of grant or tocontinue to apply our current accounting policy under Accounting PrinciplesBoard Opinion No. 25 (“APB No.25”) and recognize compensation expense, if any,based on the intrinsic value of the equity instrument at the measurementdate.  We have elected to continuefollowing APB No. 25.

             EffectiveMay 21, 1999, we amended and restated the Incentive Plan.  In conjunction with those and otheramendments of the Incentive Plan, we exchanged, on a voluntary basis, 556,488outstanding nonqualified stock options of certain of our employees anddirectors for 326,700 new common stock options in replacement of thoseoptions.   The exercise price of thereplacement options was $7.06, which represents the fair market value on thedate of grant.  The replaced optionshave a ten-year term with 50% of the options vesting immediately on the date ofgrant with the remaining 50% vesting on May 21, 2000.   On May 21, 1999, in conjunction with the repricing, we alsoissued 99,800 new ten-year common stock options to employees, which vested 100%on May 21, 2001.  The exercise price ofthe new options was $7.06, which represents the fair market value on the dateof grant.  On June 1, 1999 we issued21,000 ten-year common stock options to non-employee directors with an exerciseprice of $7.28 per share, which represents fair market value at the date ofgrant, vesting 100% on June 1, 2001.

             Anon-cash charge to compensation expense of $899,548, or $0.10 per share, wasrequired in the fourth quarter of 2000 in accordance with FASB InterpretationNo. (“FIN”) 44, “Accounting forCertain Transactions involving Stock Compensation”.  FIN 44 requires, among other things, anon-cash charge to compensation expense if the price of Edge’s common stock onthe last trading day of a reporting period is greater than the exercise priceof certain options.  FIN 44 could alsoresult in a credit to compensation expense to the extent that the trading pricedeclines from the trading price as of the end of the prior period, but notbelow the exercise price of the options. We will adjust deferred compensation expense upward or downward on amonthly basis based on the trading price at the end of each such period asnecessary to comply with FIN 44.  Thecharge is related to the non-qualified stock options granted to employees anddirectors in prior years and re-priced in May of 1999, as well as certainoptions newly issued in conjunction with the repricing discussed above.  At June 30, 2001, the price of Edge’s commonstock had declined from the price at December 31, 2000. As a result, weincluded a credit to deferred compensation expense of $(850,725), or $(0.09)per share before income taxes in the first half of 2001.

             Duringthe first quarter of 2001, we purchased options exercisable for 133,645 sharesof common stock from a former employee at a cost of $100,000, all of whichrepresents compensation expense.****6.**          **SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING ANDFINANCING ACTIVITIES**

             Weconsider all highly liquid debt instruments purchased with an original maturityof three months or less to be cash equivalents.   A summary of non-cash investing and financing activities for thesix months ended June 30, 2001 and 2000 is presented below:

             Weissued 42,103 shares of common stock with a fair market value of $126,300 atthe time of grant during the first quarter of 2001.  These shares represent one-third of the shares subject to arestricted stock grant made effective March 2, 2000.

             Inconnection with the sale of our investment in Frontera in the second quarter of2000, we recorded a receivable for $2.0 million of the proceeds that wasreceived subsequent to June 30, 2000. Additionally, we recorded an accrued liability of $87,500 in feesassociated with the sale that was paid subsequent to June 30, 2000.

             InMay 2000, a portion of the annual retainer due our non-employee directors waspaid by the issuance of 9,648 shares of common stock valued at $30,000, basedon quoted market prices on the date of issuance.

Supplemental Disclosure of Cash FlowInformation
 For  the Six Months Ended June 30,    2001 2000    Cash paid during the  period for:     Interest, net of  amounts capitalized$11,986 $78,310  Estimated alternative  minimum tax payments322,000 -- 
**7.**          **HEDGING ACTIVITIES**

             Dueto the instability of oil and natural gas prices, we enter into, from time totime, price risk management transactions (e.g., swaps and collars) for aportion of our oil and natural gas production in an effort to achieve a morepredictable cash flow, as well as to reduce exposure from pricefluctuations.  While the use of thesearrangements limits the benefit to us of increases in the price of oil andnatural gas it also limits the downside risk of adverse price movements.  Our hedging arrangements, to the extent weenter into any, typically apply to only a portion of our production, providingonly partial price protection against declines in oil and natural gas pricesand limiting potential gains from future increases in prices.  We account for these transactions as cashflow hedges under SFAS 133 and, accordingly, gains and losses are included inoil and natural gas revenue during the period the hedged production occurs.
             Theimpact on oil and natural gas revenue from hedging activities for the sixmonths ended June 30, 2001 and 2000 was as follows:

 
              Loss                  Effective  Dates         Six Months  Ended  June 30,             Hedge Type Beg. Ending Price Per Barrel Price Per MMBtu Bbl Volumes Per Day MMBtu Volumes Per Day 2001 2000          Natural  Gas Collar 2/1/00 2/29/00   $ 2.20 - $2.31   9,000 $-- $(70,470)Natural  Gas Collar 3/1/00 4/30/00   $ 2.20 - $2.50   9,000 -- (135,900)Natural  Gas Collar 5/1/00 9/30/00   $ 2.05 - $2.60   6,000 -- (409,680)Oil  Swap 1/1/00 3/31/00 $25.60   150   -- (27,521)Oil  Swap 4/1/00 6/30/00 $22.87   125   -- (55,481)Natural  Gas Collar 1/1/01 1/31/01   $ 4.50 - $6.70   4,000 (389,360)-- Amortization  of close out cost of hedge         (534,972)--             Total             $(924,332)$(699,052)                
             Ourhedging activities for natural gas are entered into on a per MMbtu deliveredprice basis, Houston Ship Channel, with settlement for each calendar month occurringfive business days following the publishing of the Inside F.E.R.C. GasMarketing Report.

             Includedwithin oil and natural gas revenue for the six months ended June 30, 2001 was$(924,332) representing net losses from hedging activity.  During December 2000, we entered into anatural gas collar covering 4,000 MMbtu per day for the period January 1, 2001to December 31, 2001 with a floor of $4.50 per MMBtu and a ceiling of $6.70 perMMbtu.  For the month of January werealized a loss on hedging activity of $(389,360).  On January 3, 2001, we closed out the hedge for the periodFebruary 1, 2001 to December 31, 2001 at a cost of $547,760. In accordance withSFAS 133, this amount is amortized over the period of the hedge based on theforward pricing curve at the time the hedge was closed out.  We recorded amortization of $(534,972) inoil and natural gas revenue for the close out cost of the hedge during thefirst half of 2001 with the balance of $(12,788) to be amortized over theremainder of the year.  At June 30,2001, we were not a party to any hedging activity.

             Includedwithin oil and natural gas revenue for the six months ended June 30, 2000 was$(699,052) representing net losses from hedging activity.  During December 1999, we entered into acrude oil fixed price swap.  The numberof barrels of oil per day (“BOD”) and the related fixed price subject to theoil price swap was as follows: i) January 1, 2000 – March 31, 2000, 150 BOD,swap at $25.60, ii) April 1, 2000 – June 30, 2000, 125 BOD, swap at $22.87,iii) July 1, 2000 – September 30, 2000, 60 BOD, swap at $21.47, and iv) October1, 2000 – December 31, 2000, 50 BOD, swap at $ 20.46. During the first quarterof 2000 we entered into three natural gas collars.  The natural gas collars cover the following periods, MMbtu perday and floor and ceiling per MMbtu prices: i) February 1, 2000 – February 29,2000, 9,000 MMbtu per day, $2.20 floor - $2.31 ceiling, ii) March 1, 2000 –April 30, 2000, 9,000 MMbtu per day, $2.20 floor - $2.50 ceiling and iii) May1, 2000 – September 30, 2000, 6,000 MMbtu per day, $2.05 floor - $2.60 ceiling.
**8.**          **SUBSEQUENT EVENTS**

             InJuly 2001, the Company was notified of a potential title problem related to ourlease covering certain properties in Starr County, Texas known as our NorthLaCopita prospect and the Neblett lease. The lease is part of a unit that contains four wells, one of which hasnot yet been completed.  At this time,the ultimate outcome of the potential title problem and the impact of suchoutcome on the Company is uncertain. Production in the unit was shut-in on August 10, 2001 pending finalresolution of the issue.  A completeloss of the property would result in the loss to the Company of approximately1.4 MMcfe per day of production, as of the time of shut-in, and approximately1.4 Bcfe of proved reserves.  TheCompany believes that an unfavorable outcome in this matter would not have amaterial impact on our financial condition.

**9.**          **COMMITMENTS AND CONTINGENCIES**

             Fromtime to time we are a party to various legal proceedings arising in theordinary course of business.  While theoutcome of lawsuits cannot be predicted with certainty, we are not currently aparty to any proceeding that we believe, if determined in a manner adverse tous, could have a potential material adverse effect on our financial condition,results of operations or cash flows except for the litigation describedbelow.  We do not believe that theultimate outcome of this litigation will have a material adverse effect on us.

             TheCompany, as one of three original plaintiffs, has filed a lawsuit against BNPPetroleum Corporation (“BNP”), Seiskin Interests, LTD, Pagenergy Company, LLCand Gap Marketing Company, LLC, as defendants, in the 229th Judicial DistrictCourt of Duval County, Texas, for fraud and breach of contract in connectionwith an agreement whereby BNP was obligated to drill a test well in an areaknown as the Slick Prospect in Duval County, Texas.  The allegations of the Company in this litigation are, ingeneral, that BNP gave the Company inaccurate and incomplete information onwhich the Company relied in entering into the transaction and in making itsdecision not to participate in the test well and the prospect, resulting in theloss of the Company’s interest in the lease, the test well and four subsequentwells drilled in the prospect.  TheCompany seeks to enforce its interest in the prospect and seeks damages orrescission, as well as costs and attorneys’ fees.  The case was originally filed in Duval County, Texas on February25, 2000.  The Company filed a *lis pendens*to protect its interest in the real property at issue.

             Inmid-March, 2000, the defendants filed an original answer and certaincounterclaims against plaintiffs, seeking unspecified damages for slander oftitle, tortious interference with business relations and exemplarydamages.  The case proceeded to trialbefore the Court (without a jury) on June 19, 2000, after the plaintiffs’ werefound by the court to have failed to comply with procedural requirementsregarding the request for a jury.  Afterseveral days of trial, the case was recessed and later resumed on September 5,2000.  The court at that time denied theplaintiffs’ motion for mistrial based on the court’s denial of a jurytrial.  The court also ordered that thedefendants’ counterclaims would be the subject of a separate trial that wouldcommence on December 11, 2000.  Theparties proceeded to try issues related to the plaintiffs’ claims on September5, 2000.  All parties rested on theplaintiffs’ claims on September 13, 2000. The court took the matter under advisement and has not yet announced aruling.  Defendants filed a secondamended answer and counterclaim and certain supplemental responses to a requestfor disclosure in which they stated that they were seeking damages in theamount of $33.5 million by virtue of an alleged lost sale of the subjectproperties, $17 million in alleged lost profits from other prospectivecontracts, and unspecified incidental and consequential damages from thealleged wrongful suspension of funds under their gas sales contract with thegas purchaser on the properties, alleged damage to relationships with tradecreditors and financial institutions, including the inability to leverage theSlick Prospect, and attorneys’ fees at prevailing hourly rates in Duval County,Texas incurred in defending against plaintiffs’ claims and for 40% of anyaggregate recovery in prosecuting their counterclaims.  In subsequent deposition testimony, the defendantsverbally alleged $26 million of damages by virtue of the alleged lost sale ofthe properties (as opposed to the $33.5 million previously sought), $7.5million of damages by virtue of loss of a lease development opportunity and$100 million of damages by virtue of the loss of a business opportunity relatedto BNP’s alleged inability to participate in a 3-D seismic project.
             TheCompany also alleged that BNP, Seiskin Interests, LTD and Pagenergy Company,LLC breached a confidentiality agreement with the plaintiffs by obtaining oiland gas leases within an area restricted by that contract. This breach ofcontract allegation is the subject of an additional lawsuit by plaintiffs inthe 165th District Court in Harris County, Texas.  In this separate action, the Company is seeking damages as a resultof defendants’ actions as well as costs and attorneys’ fees.

             Duringthe week of December 11-15, 2000, BNP tried its counterclaims against Edge, andEdge presented its defenses to the counterclaims.  BNP presented evidence that its damages were in the amounts of$19.6 million for the alleged lost sale of the properties, $35 million for lossof the lease development opportunity, and $308 million for loss of theopportunity related to participation in the 3-D seismic project.  During the course of the trial, Edgepresented its motion for summary judgment on the counterclaims based on thedoctrine of absolute judicial proceeding privilege.   The judge partially granted Edge’s motion for summary judgmentas it related to the filing of the lis pendens, but denied it with regard tothe other allegations of BNP.   Thejudge also granted Edge’s plea in abatement relating to the breach of theconfidentiality agreement, ruling that the District Court in Harris County hasdominant jurisdiction of that issue.  Atthe conclusion of this trial, the court took the matter under advisement.   The parties have filed overviews of theevidence, proposed findings of fact and conclusions of law and proposedcharges.   The court has not yet ruledbut has requested that the parties file proposed forms of judgment, which theparties have done.

             Whilethe Company believes it has presented sufficient legal and factual defenses toall of the defendants’ counterclaims, and has vigorously defended itself inthis matter, there can be no assurance that the outcome of any portion of thislitigation will be favorable to the Company. In the possible event of a material adverse outcome on the counterclaimsor related matters, there could be a material adverse effect on theCompany.  In that event, the Companymight well be required to post a bond in the amount of the judgment (or theportion of the counterclaim judgment for which it has liability) in order toprevent the defendants from executing on that judgment.  Depending on the amount of such a judgment,there could be no assurance that the Company could obtain such a bond or paythe judgment.  In the event of anadverse judgment, the Company would likely appeal such judgment, and theCompany is optimistic about its chances for success on appeal, should such benecessary.  However, there can be noassurance as to the outcome of this matter.ITEM  2.MANAGEMENT’S  DISCUSSION AND ANALYSIS OF FINANCIAL   CONDITION AND RESULTS OF OPERATIONS
             The following is management’sdiscussion and analysis of certain significant factors that have affectedcertain aspects of our financial position and operating results during theperiods included in the accompanying unaudited condensed consolidated financialstatements.  This discussion should beread in conjunction with the accompanying unaudited condensed consolidatedfinancial statements included elsewhere in this Form 10-Q and with our auditedconsolidated financial statements included in our annual report on Form 10-Kfor the year ended December 31, 2000.

***             Overview***

             Thefollowing matters had a significant impact on our results of operations andfinancial position for the six months ended June 30, 2001:

*             CommodityPrices* – The average realizedprice for our production, before the effects of hedging activity, increased 82%from $3.07 per thousand cubic feet of gas equivalent (Mcfe) in the first halfof 2000 to $5.60 per Mcfe for the comparable period this year.  Hedging activity for the six months endedJune 30, 2001 resulted in a net loss of $924,332, or $0.26 per Mcfe, comparedto a net loss of  $699,052, or $0.23 perMcfe, for the same period in 2000.

*             Debt*–As of June 30, 2001, there were no borrowings outstanding under our CreditFacility. Our current borrowing base is $14 million and no automatic monthlyreductions are required.  The borrowingbase will be redetermined on a semi-annual basis.

*             Deferred compensation*- A non-cash charge to compensation expense of $899,548, or $0.10 per share,was required in the fourth quarter of 2000 in accordance with FASBInterpretation No. (“FIN”) 44, “*Accountingfor Certain Transactions involving Stock Compensation*”.  At June 30, 2001, the price of Edge’s commonstock had declined from the price at December 31, 2000 and as a result, weincluded a credit to deferred compensation expense of $(850,725), or $(0.09)per share before income taxes in the first half of 2001.

*             IncomeTaxes* – Based on our currentexpectation of net income for the year ended December 31, 2001, we anticipateutilizing all of our available net tax assets during 2001.  As a result, a provision for deferred taxesof  $781,595, or $0.08 per share wasincluded in our first half results. This represents an effective rate of 8% atJune 30, 2001 compared to a 12% rate at March 31, 2001, resulting in an incometax benefit in the second quarter of $240,076, or $0.03 per share.

***             RESULTS OF OPERATIONS***

**Revenue and Production**

             Oiland natural gas revenue for the second quarter of 2001 increased 72% over thesame period in 2000.  Natural gasproduction comprised 88% of total production on an equivalent Mcf basis andcontributed 88% of total revenue for the second quarter of 2001. Oil andcondensate production was 10% of total production and contributed 10% of totaloil and gas revenue while natural gas liquids (NGLs) production comprised 2% oftotal production and contributed 1% of total oil and gas revenue.  Other oil and gas revenue related tomarketing activities contributed 1% to total revenue.  In the comparable 2000 period, natural gas production comprised79% of total production and contributed 77% of total revenue.  Oil and condensate production was 11% oftotal production and 14% of revenue and NGLs production comprised 10 % of totalproduction and contributed 9% of total revenue.
             Oiland natural gas revenue for the first half of 2001 increased 130% over the sameperiod in 2000.  Natural gas productioncomprised 90% of total production and contributed 90% of total revenue for thefirst half of 2001. Oil and condensate production was 9% of total production andcontributed 7% of total oil and gas revenue while NGLs production comprised 1%of total production and contributed 1% of total oil and gas revenue.  Other oil and gas revenue related tomarketing activities contributed 2% to total revenue.  In the comparable 2000 period, natural gas production comprised79% of total production and contributed 75% of total revenue.  Oil and condensate production was 10% oftotal production and 15% of revenue and NGLs production comprised 11% of totalproduction and contributed 10% of total revenue.

             Thefollowing table summarizes volume and price information with respect to our oiland gas production for the quarter and year-to-date periods ended June 30, 2001and 2000:

 
 For  the Three Months Ended June 30, For  the Six Months Ended June 30,     2001 2000 Increase  (Decrease) 2001 2000 Increase  (Decrease)                     Gas Volume – MCFGPD  (1)17,697 13,994 3,703 17,826 13,021 4,805 Average Gas Price –  per MCF$4.43 $3.25 $1.18 $5.75 $2.96 $2.79 Hedge Loss – per MCF$(0.03)$(0.41)$0.38 $(0.29)$(0.26)$(0.03)             Oil and Condensate  Volume – BPD (2)333 320 13 293 283 10 Average Oil Price –  per barrel$25.90 $24.03 $1.87 $27.10 $25.61 $1.49 Hedge Loss – per  barrel$— $(1.91)$1.91 $— $(1.61)$1.61              Natural Gas Liquids  Volume – BPD (2)63 293 (230)49 292 (243)Average NGL Price –  per barrel$16.27 $15.60 $0.67 $18.12 $15.97 $2.15              Other oil and gas  revenue – per Mcfe$0.05 -- $0.05 $0.09 -- $0.09 (1)MCFGPD – thousand  cubic feet of gas per day(2)BPD – barrels per day
**Second Quarter 2001 Compared to the Second Quarter 2000**

             Naturalgas sales revenue increased 95%, from $3.6 million for the second quarter of2000 to $7.1 million for the same period in 2001 due primarily to the impact offavorable natural gas prices and an increase in production.  In addition, losses from gas hedgingactivity were significantly lower in the second quarter of 2001 compared to thesame period in 2000. The average realized price for natural gas production,excluding the effect of hedging activity, was $4.43 per Mcf for the secondquarter of 2001, an increase of 36% over the 2000-second quarter average priceof $3.25 per Mcf.  This increase inaverage prices favorably impacted revenue by approximately $1.9 million (basedon current quarter production). Included within natural gas revenue for thethree months ended June 30, 2001 was $(49,500) representing losses from hedgingactivities.  These losses decreased theeffective natural gas price by $(0.03) per Mcf for the second quarter of2001.  For the same period in 2000, gashedging activities resulted in a loss of $(517,680) and decreased the effectivenatural gas sales price for that prior period by $(0.41) per Mcf.  Production volumes for natural gas for thethree months ended June 30, 2001 increased 26% from 13,994 MCFGPD for thesecond quarter of 2000 to 17,697 MCFGPD for the comparable period in 2001.  This increase in natural gas productionduring the second quarter of 2001 increased revenue by $1.1 million (based on2000 second quarter average prices). The increase was due to production from 22 gross (10.09 net) newsuccessful exploratory and development wells drilled and completed since June30, 2000.   Offsetting the favorableimpact of new production was a decrease in production volumes that primarilyresulted from the disposition of certain proved producing properties effectiveApril 1, 2000, further reduced by normal production declines from existingwells.
             Revenuefrom sales of oil and condensate increased 22% from $643,800 in the secondquarter of 2000 to approximately $785,000 for the comparable 2001 period dueprimarily to higher average realized prices and the absence of losses from oilhedging activities in the 2001 period. The average realized price for oil and condensate in the second quarterof 2001 was $25.90 per barrel compared to $24.03 per barrel for the same periodin 2000. This increase in the average realized price received for our oil andcondensate increased revenue $56,600 (based on current quarter production).  No oil hedges were in place for productionduring the second quarter of 2001; however, in the second quarter of 2000hedging losses of $(55,500) decreased the average realized price for oil andcondensate by $(1.91) per barrel. Production volumes for oil and condensateincreased 4% from 320 BPD in the second quarter of 2000 to 333 BPD for thecomparable period in 2001.  This slightincrease in production favorably impacted quarterly revenue by $29,200 (basedon 2000 second quarter average prices).

             Revenuefrom sales of natural gas liquids (NGLs) decreased significantly from $415,500in the second quarter of 2000 to $93,300 for the comparable 2001 period due tolower production. Production volumes for NGLs decreased 78% from 293 BPD in thesecond quarter of 2000 to 63 BPD for the comparable period in 2001.  Due to high natural gas prices, we electednot to process much of our gas during the first half of 2001.  This decrease in production decreasedquarterly revenue $326,000 (based on 2000 second quarter average prices).  The average realized price for NGLs in thesecond quarter of 2001 was $16.27 per barrel compared to $15.60 per barrel forthe same period in 2000.  This increasein the average realized price received for our NGLs increased revenue $3,800(based on current quarter production).

**Six Months Ended June 30, 2001 Compared to the Six MonthsEnded June 30, 2000**

             Naturalgas sales revenue increased 175%, from $6.4 million for the first half of 2000to approximately $17.6 million for the same period in 2001.  The impact of favorable natural gas pricesand an increase in production was partially offset by the effect of hedgingactivity. The average realized price for natural gas production, excluding theeffect of hedging activity, was $5.75 per Mcf for the first half of 2001, an increaseof 94% over the average price for the first six months of 2000 of $2.96 perMcf.  This increase in average pricesfavorably impacted revenue by approximately $9.0 million (based on currentyear-to-date production). Included within natural gas revenue for the sixmonths ended June 30, 2001 was $(924,332) representing losses from hedgingactivities.  These losses decreased theeffective natural gas price by $(0.29) per Mcf for the first half of 2001.  For the same period in 2000, gas hedgingactivities resulted in a loss of $(616,050) and decreased the effective naturalgas sales price for that prior period by $(0.26) per Mcf.  Production volumes for natural gas for thesix months ended June 30, 2001 increased 37% from 13,021 MCFGPD for the firsthalf of 2000 to 17,826 MCFGPD for the comparable period in 2001.  This increase in natural gas productionduring the first six months of 2001 increased revenue by $2.5 million (based on2000 first half average prices).  Theincrease was due to production from 22 gross (10.09 net) new successfulexploratory and development wells drilled and completed since June 30,2000.   Offsetting the favorable impactof new production was a decrease in production volumes that primarily resultedfrom the disposition of certain proved producing properties effective April 1,2000, further reduced by normal production declines from existing wells.

             Revenuefrom sales of oil and condensate increased 16% from $1.2 million in the firsthalf of 2000 to approximately $1.4 million for the comparable 2001 period dueprimarily to higher average realized prices and the absence of losses from oilhedging activities in 2001.  The averagerealized price for oil and condensate in the first half of 2001 was $27.10 perbarrel, compared to $25.61 per barrel for the same period in 2000. Thisincrease in the average realized price received for our oil and condensateincreased revenue $78,900 (based on current year-to-date production).  No oil hedges were in place for productionduring the first half of 2001; however, in the comparable 2000 period hedginglosses of $(83,002) decreased the average realized price for oil and condensateby $(1.61) per barrel. Production volumes for oil and condensate increased 4%from 283 BPD in the first half of 2000 to 293 BPD for the comparable period in2001. This slight increase in production favorably impacted year-to-daterevenue $38,100 (based on 2000 first half average prices).
             Revenuefrom sales of natural gas liquids (NGLs) decreased significantly from $850,164in the first half of 2000 to $162,158 for the comparable 2001 period due tolower production. Production volumes for NGLs decreased 83% from 292 BPD in thefirst half of 2000 to 49 BPD for the comparable period in 2001.  Due to high natural gas prices, we electednot to process much of our gas during the first six months of 2001.  This decrease in production decreasedyear-to-date revenue $707,200 (based on 2000 first half average prices).  The average realized price for NGLs in thefirst six months of 2001 was $18.12 per barrel compared to $15.97 per barrelfor the same period in 2000.  Thisincrease in the average realized price received for our NGLs increased revenue$19,200 (based on current year-to-date production).

**             Costs andOperating Expenses**

             Liftingcosts for the three-month period ended June 30, 2001 totaled $695,416, a 22%increase compared to the same period in 2000 and averaging $0.38 per Mcfe forthe three-month period ended June 30, 2001 compared to $0.36 per Mcfe in theprior year period.  For the six-monthperiod ended June 30, 2001, lifting costs totaled $1.3 million, a 29% increasecompared to the same period in 2000. Lifting costs were $0.36 per Mcfe for the six-month period ended June30, 2001 compared to $0.34 per Mcfe in the prior year period.  The increase in costs was due primarily tohigh saltwater disposal and natural gas processing costs recorded in 2001.

             Severanceand ad valorem taxes for the three months ended June 30, 2001 increased 107%from $304,143 in the prior year period to $629,407 in the second quarter of2001.  Severance and ad valorem taxesfor the six months ended June 30, 2001 increased 153% from $610,792 in theprior year period to over $1.5 million in 2001.  The increase in severance and ad valorem taxes in each of the2001 periods was due primarily to higher severance taxes paid on the increasedrevenue during the first half of 2001. Severance tax averaged 7.1% of revenue for the first half of 2001compared to 5.95% for the same period in 2000.

             Depletion,depreciation and amortization expense (“DD&A”) expense for the three-monthand six month periods ended June 30, 2001 totaled $2.5 million and $4.5million, respectively, compared to $2.2 million and $4.0 million in the sameperiods of 2000.  Full cost DD&A onour oil and natural gas properties totaled $2.3 million for the second quarterof 2001 compared to $2.0 million for the same period in 2000. Depletion expenseon a unit of production basis for the three-month periods ended June 30, 2001and 2000 was $1.26 per Mcfe for both periods. For the six months ended June 30, 2001 depletion on our oil and naturalgas properties totaled $4.1 million compared to $3.6 million for the sameperiod in 2000. Depletion expense on a unit of production basis for thesix-month periods ended June 30, 2001 and 2000 was $1.15 per Mcfe and $1.21 perMcfe, respectively.  For the first halfof 2001 as compared to the prior year period, a 6% decrease in the overalldepletion rate decreased depletion expense by $(243,900) while higher oil andnatural gas production increased depletion expense by $728,000. The decrease inthe depletion rate was primarily due to reserve revisions at December 31,2000.  Other DD&A expense totaled$169,500 and $341,179 for the three-month and six-month periods ended June 30,2001, slightly higher than the comparable prior period totals of $169,500 and$339,219, respectively.

             Generaland administrative expenses (“G&A”) for the second quarter of 2001increased 39% to $1.4 million, as compared to $1.0 million for the three monthsended June 30, 2000.  For the secondquarter of 2001 and 2000, overhead reimbursement fees recorded as a reductionto G&A totaled $75,300 and $29,600, respectively.  Capitalized G&A further reduced total G&A by $411,000 and$348,900 for the three months ended June 30, 2001 and 2000, respectively.  For the six months ended June 30, 2001,G&A, excluding deferred compensation expense related to restricted stockand FIN 44 requirements, increased 40% to $2.6 million, as compared to $1.9million for the comparable prior year period.    For the first six months of 2001 and 2000, overheadreimbursement fees recorded as a reduction to G&A totaled $80,700 and$63,000, respectively.  CapitalizedG&A further reduced total G&A by $722,000 and $762,300 for the sixmonths ended June 30, 2001 and 2000, respectively.  The increase in G&A for both periods was primarilyattributable to bad debt expense reserved in 2001, higher salaries andbenefits, and higher professional services for the first half of 2001 comparedto the same period in 2000.  Inaddition, compensation expense of $100,000 was recorded in the first quarter of2001 related to the purchase of options from a former employee.  G&A on a unit of production basis forthe six-month periods ended June 30, 2001 and 2000 was $0.73 per Mcfe ($0.65per Mcfe excluding the bad debt expense) and $0.63 per Mcfe, respectively.
             Deferredcompensation expense for the three-month and six-month periods ended June 30,2001 was a net charge of $10,409 and a net credit of $(698,748),respectively.  A non-cash credit todeferred compensation expense of $(95,400), or $(0.01) per share before incometaxes was recorded for the three months ended June 30, 2001 related to FIN 44.   Offsetting this credit was the amortizationof compensation expense of $105,800 related to restricted stock grants.  For the first half of 2001, a non-cashcredit to deferred compensation expense of $(850,725), or $(0.09) per sharebefore income taxes was recorded related to FIN 44.   In December 2000, a non-cash charge of $899,548, or $0.10 pershare, was required in accordance with FIN 44.   FIN 44 requires, among other things, a non-cash charge tocompensation expense if the price of Edge’s common stock on the last tradingday of a reporting period is greater than the exercise price of certainoptions.  FIN 44 also results in acredit to compensation expense to the extent that the trading price declinesfrom the trading price as of the end of the prior period, but not below theexercise price of the options.  Weadjust deferred compensation expense upward or downward on a monthly basisbased on the trading price at the end of each such period as necessary tocomply with FIN 44.  The adjustment isrelated only to the non-qualified stock options granted to employees anddirectors in prior years and re-priced in May of 1999, as well as certainoptions newly issued in conjunction with the repricing.  At June 30, 2001, the price of Edge’s commonstock had declined from the price at December 31, 2000 resulting in the creditto deferred compensation expense for the six months ended June 30, 2001.  Partially offsetting this credit was theamortization of compensation expense for the six-month period of $151,977related to restricted stock grants.

             Unearnedcompensation expense was fully amortized in 2000 and as a result, no expensewas reported for the first half of 2001.  For the three-month and six-month periods ended June 30, 2000 unearnedcompensation expense totaled $8,589 and $17,178, respectively.

             Interestexpense totaled $74,899 for the second quarter of 2001 compared to $46,599 inthe same quarter of 2000.  No debt wasoutstanding during the second quarter of 2001; however, finance costs of$50,000 were paid to maintain our current available borrowings of $14million.  Gross interest expense was$150,526 for the second quarter of 2000 on weighted average debt ofapproximately $6.1 million.  No interestwas capitalized in the second quarter of 2001 compared to $71,927 in the secondquarter of 2000.  Deferred loan coststotaled $24,899 for the three months ended June 30, 2001 compared to no costsin the 2000 period.  For the six monthsended June 30, 2001, interest expense totaled $108,604, including $50,000 of financecosts, compared to $90,678 in the same period of 2000.  Gross interest expense was $64,600 for thefirst half of 2001 on weighted average debt of approximately $1.0 millioncompared to gross interest expense of $325,600 on weighted average debt of approximately$6.7 million for the same prior year period. Capitalized interest in the first half of 2001 totaled $24,400 comparedto $234,900 in the first half of 2000. Deferred loan costs totaled $50,710 for the six months ended June 30,2001 compared to no costs in the 2000 period. Interest income totaled $55,928 for the second quarter of 2001 and$13,637 for the same 2000 period. Interest income totaled $78,829 for the first half of 2001 and $26,870for the comparable 2000 period.   Otherincome (expense) for the three-month and six-month periods ending June 30, 2000also included the loss on the sale of our investment in Frontera of $(354,733),or $(0.04) per share.

             Basedon our current expectation of net income for the year ended 2001, we anticipateutilizing all of our available net tax assets during 2001.  A provision for deferred taxes was includedin our first quarter 2001 results of approximately $(1.0) million, or $(0.11)per share, an effective rate of approximately 12%.  At June 30, 2001, we revised our estimated effective tax rate forthe year to 8% based on current forecast information.  Income tax expense for the six months ended June 30, 2001 at thecurrent effective rate was $(781,595) or $(0.08) per share.  As a resultof this change in the effective rate, an income tax benefit was reported forthe quarter ended June 30, 2001 of $240,076. No expense (benefit) was recorded for the three-month or six-monthperiods ended June 30, 2000 due to the estimated deferred tax asset at thattime.

             Forthe second quarter of 2001, we reported net income of $3,055,992 or $0.33 basicearnings per share, compared to net income of $208,591, or $0.02 basic earnings per share, for the same period in2000.  Pro forma net income, excludingthe non-cash compensation credit related to FIN 44, was $2,967,883, or $0.32per share, for the second quarter of 2001. Weighted average shares outstandingincreased from approximately 9,179,309 shares for the three months ended June30, 2000 to 9,289,027 shares in the comparable 2001 period.  The increase was due primarily to theexercise of stock options and the issuance of common stock related to a 2000restricted stock grant.

             Forthe six months ended June 30, 2001, we reported net income of $9,506,508 or$1.03 basic earnings per share, compared to net income of  $567,862, or $0.06 basic earnings per share,for the same period in 2000.  Pro formanet income, excluding the non-cash compensation credit related to FIN 44, was$8,720,413, or $0.95 per share. Weighted average shares outstanding increasedfrom approximately 9,178,407 shares for the six months ended June 30, 2000 to9,256,680 shares in the comparable 2001 period.  The increase was due primarily to the exercise of stock optionsand the issuance of common stock related to a 2000 restricted stock grant.******             LIQUIDITY AND CAPITAL RESOURCES***

             Ourprimary cash needs are for exploration, development and acquisition of oil andgas properties, and repayment of principal and interest on outstanding debt.Due to our active exploration and development and technology enhancementprograms, we have experienced and expect to continue to experience substantialworking capital requirements.  We intendto fund our remaining 2001 capital expenditures, commitments and workingcapital requirements through cash flows from operations, and to the extentnecessary other financing activities. At our August 1, 2001 meeting of the Board of Directors, we approved anincrease in our capital budget for the year 2001 from $23.3 million to $28.1million.  We believe we will be able togenerate capital resources and liquidity sufficient to fund our capitalexpenditures and meet such financial obligations as they come due.  In the event such capital resources are notavailable us, drilling and other activities may be curtailed.

*Liquidity*

             Wehad cash and cash equivalents at June 30, 2001 of $6.4 million consistingprimarily of short-term money market investments, as compared to $247,981 atDecember 31, 2000.  Our workingcapital surplus was $8.8 million at June 30, 2001, as compared to $2.9 millionat December 31, 2000, as revised. Our ratio of current assets to currentliabilities was 3.7:1 at June 30, 2001 compared to 1.4:1 at December 31, 2000.At June 30, 2001, no borrowings were outstanding under our Credit Facility.  At December 31, 2000, borrowings totaled$3.0 million.  Excluding such currentportion of long-term debt at December 30, 2000, we had a working capitalsurplus of $5.9 million and our ratio of current assets to current liabilitieswas 2.5:1.  Our increases in workingcapital surplus and current ratio at June 30, 2001 resulted primarily from ourability to reduce accounts payable and accrued liabilities with the strong cashflow from operations.

*Cash Flows*

             Cashflows provided by operations were $16.9 million and $2.3 million for the sixmonths ended June 30, 2001 and 2000, respectively.  The increase in cash flows provided by operations is primarilydue to an increase in net income from $567,862 in the first half of 2000 to$9.5 million for the same period in 2001. The six-month period ended June 30, 2001 was a record for us in terms ofboth revenue and net income, allowing us the flexibility to repay borrowingsand reduce current liabilities. Improvements in working capital for the six months ended June 30, 2001increased cash flow $2.6 million as compared to working capital usage of $(2.6)million for the same period in 2000. Operating cash flows, before changes inworking capital, were $14.4 million and $4.9 million for the six months endedJune 30, 2001 and 2000, respectively. Operating cash flow should not be considered in isolation or as asubstitute for net income, operating income, cash flows from operatingactivities or any other measure of financial performance presented in accordancewith generally accepted accounting principles or as a measure of profitabilityor liquidity.

             Cashused in investing activities totaled $8.2 million for the six months ended June30, 2001 compared to $135,528 used in the same period of 2000.  Capital expenditures during the six monthsended June 30, 2001 were approximately $8.2 million as compared to $3.5 millionduring the same period in 2000.  Weexpended $3.8 million in our drilling operations resulting in the drilling of 5gross (3.27 net) wells during the first half of 2001 as compared to 7 gross(1.84 net) wells during the same period in 2000.  Since June 30, 2001, we have drilled four successful grosswells.  Currently, one gross well istesting and three gross wells are drilling. In addition to capital expenditures for drilling operations,approximately $1.2 million was incurred on currently producing properties and$2.3 million was expended on land and seismic activities.  The remaining cost capitalized to oil andnatural gas properties was internal G&G and interest of approximately $846,400.  Total capital expenditures for 2001 areexpected to be approximately $28.1 million. For the six months ended June 30,2000, other investing activity also included proceeds from the sale of oil andnatural gas properties of $1.8 million and proceeds from the sale of ourinvestment in Frontera of $1.6 million.
             Cashused in financing activities totaled $2.6 million for the six months ended June30, 2001 and included borrowings of $1.0 million and repayments of $4.0 millionunder our Credit Facility.   Otherfinancing activities included net proceeds from the exercise of stock optionsof $390,801.  For the six months endedJune 30, 2000, cash used in financing activities totaled $2.15 million, whichincluded borrowings of $850,000 and repayments of $3,000,000.

**             CreditFacility**

             Duringthe first quarter of 2001, we repaid all amounts borrowed under our CreditFacility and as of June 30, 2001, no borrowings were outstanding. Futureborrowings under the Credit Facility, if any, will bear interest at a rateequal to prime plus 0.50% or LIBOR plus 2.75%. The Credit Facility matures October 2, 2002 and is secured bysubstantially all of our assets.

             Originallythe borrowing base under the Credit Facility was $5 million and was subject toautomatic reductions at a rate of $300,000 per month beginning February 28,2001.  In March 2001, the CreditFacility was amended to increase the borrowing base to $14 million, and toeliminate the $300,000 per month automatic reduction.  The borrowing base will be redetermined on a semi-annualbasis.  The Company expects theborrowing base to be redetermined in the third quarter of 2001.

             TheCredit Facility provides for certain restrictions, including but not limitedto, limitations on additional borrowings and issues of capital stock, sales ofoil and natural gas properties or other collateral, engaging in merger orconsolidation transactions. The Credit Facility also prohibits dividends andcertain distributions of cash or properties and certain liens.  The Credit Facility also contains certainfinancial covenants. The EBITDA to Interest Expense Ratio requires that (a)consolidated EBITDA, as defined in the agreement, of the Company for the fourfiscal quarters then ended to (b) the consolidated interest expense of the Companyfor the four fiscal quarters then ended, to not be less than 3.5 to 1.0.  The Working Capital ratio requires that theamount of the Company’s consolidated current assets less its consolidatedliabilities, as defined in the agreement, be at least $1.0 million.  The Allowable Expenses ratio requires that(a) the aggregate amount of the Company’s year to date consolidated general andadministrative expenses for the period from January 1 of such year through thefiscal quarter then ended to (b) the Company’s year to date consolidated oiland gas revenue, net of hedging activity, for the period from January 1 of suchyear through the fiscal quarter then ended, to be less than .40 to 1.0.  At June 30, 2001, the Company was incompliance with the above mentioned covenants.

**             AccountingPronouncements**

***             Derivatives***– We adopted Statement of Financial Accounting Standards No. 133, “Accountingfor Derivative Instruments and Hedging Activities” (“SFAS 133”) effectiveJanuary 1, 2001.  The statement, asamended, requires that all derivatives be recognized as either assets orliabilities and measured at fair value, and changes in the fair value ofderivatives be reported in current earnings, unless the derivative isdesignated and effective as a hedge.  Ifthe intended use of the derivative is to hedge the exposure to changes in thefair value of an asset, a liability or firm commitment, then the changes in thefair value of the derivative instrument will generally be offset in the incomestatement by the change in the item’s fair value.  However, if the intended use of the derivative is to hedge theexposure to variability in expected future cash flows then the changes in fairvalue of the derivative instrument will generally be reported in OtherComprehensive Income (“OCI”).  The gainsand losses on the derivative instrument that are reported in OCI will bereclassified to earnings in the period in which earnings are impacted by thehedged item.
             Wewill account for our natural gas and crude oil hedge derivative instruments ascash flow hedges under SFAS 133. Although the fair value of our derivative instruments fluctuates daily,as of January 1, 2001, the fair value of the our natural gas hedge derivativeinstrument was approximately ($1.1) million, which was recorded in theConsolidated Balance Sheet on January 1, 2001. The ($1.1) million was recorded as a liability on our balance sheet aspart of the transition adjustment related to our adoption of SFAS 133.  The offset to this balance sheet adjustmentwas a decrease to “Accumulated Other Comprehensive Income”, a component ofstockholders’ equity. In early January, we closed out of our hedge obligationfor the period from February 1, 2001 to December 31, 2001.  As a result, we recorded a loss on theJanuary hedge of $389,360 and are amortizing the close out cost of $547,760based on the forward pricing curve at the time of the close out in accordancewith SFAS 133.  Included in earnings forthe first half of 2001 is a charge of $924,332 representing the loss in Januaryand the amortized portion of the close out cost as of June 30, 2001.  The unamortized balance of the close outcost of  $12,788 is included instockholders’ equity as accumulated other comprehensive loss.  As of June 30, 2001, we were not a party toany hedging activity.

             OnJune 29, 2001, the FASB approved its proposed SFAS No. 141, ("FAS141")  "BusinessCombinations," and SFAS No. 142 ("FAS 142"), "Goodwill andOther Intangible Assets."  UnderFAS 141, all business combinations should be accounted for using the purchasemethod of accounting; use of the pooling-of-interests method is prohibited. Theprovisions of the statement will apply to all business combinations initiatedafter June 30, 2001.

             FAS142 will apply to all acquired intangible assets whether acquired singly, aspart of a group, or in a business combination. The statement will supersedeAccounting Principals Board, ("APB"), Opinion No. 17,"Intangible Assets," and will carry forward provisions in APB OpinionNo.17 related to internally developed intangible assets. Adoption of FAS 142will result in ceasing amortization of goodwill. All of the provisions of thestatement should be applied in fiscal years beginning after December 15, 2001to all goodwill and other intangible assets recognized in an entity's statementof financial position at that date, regardless of when those assets wereinitially recognized.

             TheCompany does not expect the adoption of these standards to have a materialeffect on its consolidated financial statements.

***             FORWARDLOOKING STATEMENTS***

             Thestatements contained in all parts of this document, including, but not limitedto, those relating to our drilling plans, our 3-D project portfolio, capitalexpenditures, future capabilities, the sufficiency of capital resources andliquidity to support working capital and capital expenditure requirements,reinvestment of cash flows, the outcome of litigation, the resolution of titlematters and any other statements regarding future operations, financialresults, business plans, sources of liquidity and cash needs and otherstatements that are not historical facts are forward looking statements.  When used in this document, the words“anticipate,” “estimate,” “expect,” “may,” “project,” “believe” and similarexpressions are intended to be among the statements that identify forwardlooking statements.  Such statementsinvolve risks and uncertainties, including, but not limited to, those relatingto our dependence on our exploratory drilling activities, the volatility of oiland natural gas prices, the need to replace reserves depleted by production,operating risks of oil and natural gas operations, our dependence on keypersonnel, our reliance on technological development and possible obsolescenceof the technology currently used by us, significant capital requirements of ourexploration and development and technology development programs, the potentialimpact of government regulations, litigation, environmental and title matters,our ability to manage our growth and achieve our business strategy,competition, the uncertainty of reserve information and future net revenueestimates, property acquisition risks and other factors detailed in our Form10-K and other filings with the Securities and Exchange Commission.  Should one or more of these risks oruncertainties materialize, or should underlying assumptions prove incorrect,actual outcomes may vary materially from those indicated.

***ITEM 3.  QUALITATIVE AND QUANTITATIVE DISCLOSUREABOUT MARKET RISK***

             Weare exposed to market risk from changes in interest rates and commodityprices.  We use a Credit Facility, whichhas a floating interest rate, to finance a portion of our operations. We arenot subject to fair value risk resulting from changes in our floating interestrates.  The use of floating rate debtinstruments provides a benefit due to downward interest rate movements but doesnot limit us to exposure from future increases in interest rates.  At June 30, 2001, no borrowings wereoutstanding under our Credit Facility.

             Inthe normal course of business we enter into hedging transactions, includingcommodity price collars and swaps, to mitigate our exposure to commodity pricemovements, but not for trading or speculative purposes. In December 2000, dueto the instability of natural gas prices and to achieve a more predictable cashflow, we had in place a natural gas collar for a portion of our year 2001natural gas production.  The natural gascollar covered 4,000 MMbtu per day for the period January 1, 2001 to December31, 2001 at a floor of $4.50 per MMbtu and a ceiling of $6.70 per MMbtu. OnJanuary 3, 2001, we closed out the hedge for the period February 1, 2001 toDecember 31, 2001 at a cost of $547,760. Currently, there are no natural gascollars in place for any future periods.****PART II - OTHER INFORMATION**

**Item 1 - Legal Proceedings**

             Fromtime to time we are a party to various legal proceedings arising in theordinary course of business.  While theoutcome of lawsuits cannot be predicted with certainty, we are not currently aparty to any proceeding that we believe, if determined in a manner adverse tous, could have a potential material adverse effect on our financial condition,results of operations or cash flows except for the litigation described below.  We do not believe that the ultimate outcomeof this litigation will have a material adverse effect on us.

             TheCompany, as one of three original plaintiffs, has filed a lawsuit against BNPPetroleum Corporation (“BNP”), Seiskin Interests, LTD, Pagenergy Company, LLCand Gap Marketing Company, LLC, as defendants, in the 229th Judicial DistrictCourt of Duval County, Texas, for fraud and breach of contract in connectionwith an agreement whereby BNP was obligated to drill a test well in an areaknown as the Slick Prospect in Duval County, Texas.  The allegations of the Company in this litigation are, ingeneral, that BNP gave the Company inaccurate and incomplete information onwhich the Company relied in entering into the transaction and in making itsdecision not to participate in the test well and the prospect, resulting in theloss of the Company’s interest in the lease, the test well and four subsequentwells drilled in the prospect.  TheCompany seeks to enforce its interest in the prospect and seeks damages orrescission, as well as costs and attorneys’ fees.  The case was originally filed in Duval County, Texas on February25, 2000.  The Company filed a *lis pendens*to protect its interest in the real property at issue.

             Inmid-March, 2000, the defendants filed an original answer and certaincounterclaims against plaintiffs, seeking unspecified damages for slander oftitle, tortious interference with business relations and exemplarydamages.  The case proceeded to trialbefore the Court (without a jury) on June 19, 2000, after the plaintiffs’ werefound by the court to have failed to comply with procedural requirementsregarding the request for a jury.  Afterseveral days of trial, the case was recessed and later resumed on September 5,2000.  The court at that time denied theplaintiffs’ motion for mistrial based on the court’s denial of a jurytrial.  The court also ordered that thedefendants’ counterclaims would be the subject of a separate trial that wouldcommence on December 11, 2000.  Theparties proceeded to try issues related to the plaintiffs’ claims on September5, 2000.  All parties rested on theplaintiffs’ claims on September 13, 2000. The court took the matter under advisement and has not yet announced aruling.  Defendants filed a secondamended answer and counterclaim and certain supplemental responses to a requestfor disclosure in which they stated that they were seeking damages in theamount of $33.5 million by virtue of an alleged lost sale of the subjectproperties, $17 million in alleged lost profits from other prospectivecontracts, and unspecified incidental and consequential damages from thealleged wrongful suspension of funds under their gas sales contract with thegas purchaser on the properties, alleged damage to relationships with tradecreditors and financial institutions, including the inability to leverage theSlick Prospect, and attorneys’ fees at prevailing hourly rates in Duval County,Texas incurred in defending against plaintiffs’ claims and for 40% of anyaggregate recovery in prosecuting their counterclaims.  In subsequent deposition testimony, thedefendants verbally alleged $26 million of damages by virtue of the allegedlost sale of the properties (as opposed to the $33.5 million previouslysought), $7.5 million of damages by virtue of loss of a lease developmentopportunity and $100 million of damages by virtue of the loss of a businessopportunity related to BNP’s alleged inability to participate in a 3-D seismicproject.

             TheCompany also alleged that BNP, Seiskin Interests, LTD and Pagenergy Company,LLC breached a confidentiality agreement with the plaintiffs by obtaining oiland gas leases within an area restricted by that contract. This breach ofcontract allegation is the subject of an additional lawsuit by plaintiffs inthe 165th District Court in Harris County, Texas.  In this separate action, the Company is seeking damages as aresult of defendants’ actions as well as costs and attorneys’ fees.
             Duringthe week of December 11-15, 2000, BNP tried its counterclaims against Edge, andEdge presented its defenses to the counterclaims.  BNP presented evidence that its damages were in the amounts of$19.6 million for the alleged lost sale of the properties, $35 million for lossof the lease development opportunity, and $308 million for loss of theopportunity related to participation in the 3-D seismic project.  During the course of the trial, Edgepresented its motion for summary judgment on the counterclaims based on thedoctrine of absolute judicial proceeding privilege.   The judge partially granted Edge’s motion for summary judgmentas it related to the filing of the lis pendens, but denied it with regard tothe other allegations of BNP.   Thejudge also granted Edge’s plea in abatement relating to the breach of theconfidentiality agreement, ruling that the District Court in Harris County hasdominant jurisdiction of that issue.  Atthe conclusion of this trial, the court took the matter under advisement.   The parties have filed overviews of theevidence, proposed findings of fact and conclusions of law and proposedcharges.   The court has not yet ruledbut has requested that the parties file proposed forms of judgment, which theparties have done.

             Whilethe Company believes it has presented sufficient legal and factual defenses toall of the defendants’ counterclaims, and has vigorously defended itself inthis matter, there can be no assurance that the outcome of any portion of thislitigation will be favorable to the Company. In the possible event of a material adverse outcome on the counterclaimsor related matters, there could be a material adverse effect on theCompany.  In that event, the Companymight well be required to post a bond in the amount of the judgment (or theportion of the counterclaim judgment for which it has liability) in order toprevent the defendants from executing on that judgment.  Depending on the amount of such a judgment,there could be no assurance that the Company could obtain such a bond or paythe judgment.  In the event of anadverse judgment, the Company would likely appeal such judgment, and theCompany is optimistic about its chances for success on appeal, should such benecessary.  However, there can be noassurance as to the outcome of this matter.
**Item  2 - Changes in Securities and Use of Proceeds**None  **Item  3 - Defaults Upon Senior Securities**None  **Item  4 - Submission of Matters to a Vote of Security Holders** 
(A)       AnnualMeeting of Shareholders on May 2, 2001.(B)        Set fourth below are theresults of the voting with respect to each matter acted upon:
 For Against Withheld Abstain Broker    Non Votes       Election of Directors:           Stanley S. Raphael6,845,196   813,883      Robert W. Shower7,636,728   22,351                Approval of the  Appointment of Deloitte and Touche LLP as independent Public Accountants7,623,384 20,504   15,191   
In addition to the election of thedirectors indicated above, the terms of the following directors continued asdirectors following the meeting: Vincent S. Andrews, David B. Benedict, Nils P.Peterson, John W. Elias and John Sfondrini.
**Item  5 - Other Information**None  **Item  6 - Exhibits and Reports on Form 8-K** 
 

             (A)       EXHIBITS.  The following exhibits are filed as part ofthis report:

**INDEX TO EXHIBITS**
Exhibit  No.    †2.1 —         Amended and Restated Combination  Agreement by and among (i) Edge Group II Limited Partnership, (ii) Gulfedge  Limited Partnership, (iii) Edge Group Partnership, (iv) Edge Petroleum  Corporation, (v) Edge Mergeco, Inc. and (vi) the Company, dated as of  January 13, 1997 (Incorporated by reference from exhibit 2.1 to the  Company’s Registration Statement on Form S-4 (Registration No. 333-17269))†3.1 —         Restated Certificate of Incorporated  of the Company, as amended (Incorporated by reference from exhibit 3.1 to the  Company’s Registration Statement on Form S-4 (Registration No. 333-17269)).†3.2 —         Bylaws of the Company  (Incorporated by Reference from exhibit  3.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period  ended September 30, 1999).†3.3 —         First Amendment to Bylaws of the  Company on September 28, 1999 (Incorporated by Reference from exhibit 3.2 to  the Company’s Quarterly Report on Form 10-Q for the quarterly period ended  September 30, 1999).†4.1 —         Security Agreement, dated as of April  1, 1998, by and between the Borrower and Compass Bank, a Texas state  chartered banking institution, as Agent for itself and The First National  Bank of Chicago and other lenders party thereto the Credit Agreement (Incorporated  by Reference from exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q  for the quarterly period ended March 31, 1998).†4.2 —         Security Agreement (Stock Pledge),  dated as of April 1, 1998, by and between Edge Petroleum Corporation and  Compass Bank, a Texas state chartered banking institution, as Agent for  itself and The First National Bank of Chicago and other lenders party thereto  the Credit Agreement (Incorporated by Reference from exhibit 4.1 to the  Company’s Quarterly Report on Form 10-Q for the quarterly period ended March  31, 1998).†4.3 —         Second Amended and Restated Credit  Agreement dated October 6, 2000 by and between Edge Petroleum Corporation,  Edge Petroleum Exploration Company and Edge Petroleum Operating Company, Inc.  (collectively, the “Borrowers”) and Union Bank Of California, N.A., a  national banking association, as Agent for itself and as lender.  (Incorporated by Reference from exhibit 4.5 to the Company’s Quarterly Report  on Form 10-Q for the quarterly period ended September 31, 2000).†4.4 —         Letter Agreement  dated October 31, 2000 by and between Edge  Petroleum Corporation, Edge Petroleum Exploration Company and Edge Petroleum  Operating Company, Inc. (collectively, the “Borrowers”) and Union Bank Of California,  N.A., a national banking association, as Agent for itself and as lender.  (Incorporated by Reference from exhibit  4.6 to the Company’s Quarterly Report on Form 10-Q for the quarterly period  ended September 31, 2000).†4.5 —         Letter Agreement  dated March 23, 2001 by and between Edge  Petroleum Corporation, Edge Petroleum Exploration Company and Edge Petroleum  Operating Company, Inc. (collectively, the “Borrowers”) and Union Bank Of  California, N.A., a national banking association, as Agent for itself and as  lender. (Incorporated by Reference from exhibit 4.5 to the Company’s Annual  Report on Form 10-K for the annual period ended December 31, 2000).†4.6 —         Common Stock Subscription Agreement  dated as of April 30, 1999 between the Company and the purchasers named therein  (Incorporated by reference from exhibit 4.5 to the Company’s Quarterly Report  on Form 10-Q/A for the quarter ended March 31, 1999).†4.7 —         Warrant Agreement dated as of May 6,  1999 between the Company and the Warrant holders named therein (Incorporated  by reference from exhibit 4.5 to the Company’s Quarterly Report on Form  10-Q/A for the quarter ended March 31, 1999).†4.8 —         Form of Warrant for the purchase of  the Common Stock (Incorporated by reference from the Common Stock  Subscription Agreement from exhibit 4.5 to the Company’s Quarterly Report on  Form 10-Q/A for the quarter ended March 31, 1999).†10.1 —         Joint Venture Agreement between Edge  Joint Venture II and Essex Royalty Limited Partnership II, dated as of May  10, 1994 (Incorporated by reference from exhibit 10.2 to the Company’s  Registration Statement on Form S-4 (Registration No. 333-17269)).†10.2 —         Joint Venture Agreement between Edge  Joint Venture II and Essex Royalty Limited Partnership, dated as of April 11,  1992 (Incorporated by reference from exhibit 10.3 to the Company’s  Registration Statement on Form S-4 (Registration No. 333-17269)).†10.3 —         Form of Indemnification Agreement  between the Company and each of its directors (Incorporated by reference from  exhibit 10.7 to the Company’s Registration Statement on Form S-4  (Registration No. 333-17269)).†10.4 —         Stock Option Plan of Edge Petroleum  Corporation, a Texas corporation (Incorporated by reference from exhibit  10.13 to the Company’s Registration Statement on Form S-4 (Registration No.  333-17269)).†10.5 —         Employment Agreement dated as of  November 16, 1998, by and between the Company and John W. Elias.  (Incorporated by reference from 10.12 to the Company’s Annual Report on Form  10-K for the year ended December 31, 1998).*10.6 —         Incentive Plan of Edge Petroleum  Corporation as Amended and Restated Effective as of July 27, 1999 and as  amended March 1, 2001.†10.7 —         Edge Petroleum Corporation Incentive  Plan “Standard Non-Qualified Stock Option Agreement” by and between Edge  Petroleum Corporation and the Officers named therein. (Incorporated by  reference from exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q  for the quarterly period ended September 30, 1999).†10.8 —         Edge Petroleum Corporation Incentive  Plan “Director Non-Qualified Stock Option Agreement” by and between Edge  Petroleum Corporation and the Directors named therein. (Incorporated by  reference from exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q  for the quarterly period ended September 30, 1999).†10.9 —         Severance Agreements by and between  Edge Petroleum Corporation and the Officers of the Company named therein.  (Incorporated by reference from exhibit 10.4 to the Company’s Quarterly  Report on Form 10-Q for the quarterly period ended September 30, 1999).†10.10 —         Form of Employee Restricted Stock  Award Agreement under the Incentive Plan of Edge Petroleum Corporation  (Incorporated by Reference from exhibit 10.15 to the Company’s Quarterly  Report on Form 10-Q/A for the quarterly period ended March 31, 1999).†10.11 —         Edge Petroleum Corporation Amended  and Restated Elias Stock Incentive Plan.   (Incorporated by reference from exhibit 4.5 to the Company’s  Registration Statement on Form S-8 filed May 30, 2001 (Registration No. 333-61890)).†10.12 —         Form of Edge Petroleum Corporation  John W. Elias Non-Qualifies Stock Option Agreement (Incorporated by reference  from exhibit 4.6 to the Company’s Registration Statement on Form S-8 filed  May 30, 2001 (Registration No. 333-61890)).
 
*Filed  herewith.†Incorporated  by reference as indicated.
 
 (B)Reports  on Form 8-KNone
 

**SIGNATURES**

             Pursuantto the requirements of the Securities Exchange Act of 1934, the registrant hasduly caused this report to be signed on its behalf by the undersigned thereuntoduly authorized.

EDGEPETROLEUM CORPORATION,A DELAWARE CORPORATION(REGISTRANT)
      Date8/14/01 /S/John W. Elias     John W. Elias    Chief Executive  Officer and    Chairman of the Board     Date8/14/01 /S/Michael G. Long     Michael G. Long    Senior Vice President  and    Chief Financial and  Accounting Officer
 *******