** **

**UNITED STATES SECURITIES AND EXCHANGE COMMISSION**

# **Washington, D.C. 20549**

# ** **

#### **FORM 10-K**

#### ** **

**ý****        ****ANNUAL REPORT PURSUANT TO SECTION 13OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**

 

**For the fiscal year ended December 31,2004**

 

**OR**

 

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

 

##### **For the transition period from      to      **

##### ** **

**Commission file number:  0-22149**

 

#### **EDGE PETROLEUM CORPORATION**

(Exact name of Registrant as specified in its charter)

 
| **Delaware**                                                    |   | **76-0511037**                        |
|-----------------------------------------------------------------|--------|---------------------------------------|
| (State or other jurisdiction of  incorporation or organization) |   | (I.R.S. Employer  Identification No.) |
|                                                            |   |                                  |
| **1301 Travis, Suite 2000  Houston, Texas**                     |   | **77002**                             |
| (Address of principal executive offices)                        |   | (Zip code)                            |

 

**713-654-8960**

(Registrant’s telephonenumber including area code)

 

Securities registeredpursuant to Section 12(b) of the Act:

**None**

 

Securities registeredpursuant to Section 12(g) of the Act:

**Common Stock, Par Value $.01 PerShare**

 

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

 

Yes  ý    No  o

 

Indicate by check markif disclosure of delinquent filers pursuant to Item 405 of Regulation S-K isnot contained herein, and will not be contained, to the best of registrant’sknowledge, in definitive proxy or information statements incorporated byreference in Part III of this Form 10-K or any amendment to this Form 10-K.  ý

 

Indicate by check markwhether the registrant is an accelerated filer.

 

Yes  ý    No  o

 

As of June 30, 2004, the aggregate market value of the voting stockheld by non-affiliates of the registrant was $210.5 million (based on a valueof $17.00 per share, the closing price of the Common Stock as quoted by NASDAQNational Market on such date).

 

As of March 11,2005, 17,100,155 shares of Common Stock, par value $.01 per share, wereoutstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

***Portions of the definitive proxystatement for the registrant’s 2005 Annual Meeting of Shareholders, to be filedpursuant to Regulation 14A under the Securities Exchange Act of 1934, are incorporatedby reference into Part III of this report.***

 

 

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***TABLE OF CONTENTS***

*** ***
| ***PART  I***        |
|----------------------|
| *** ***         | *** *** | *** *** |
| ***ITEMS 1 AND 2.*** | ***BUSINESS AND PROPERTIES*** | *** *** |
| *** ***         | *** *** | *** *** |
| ***ITEM 3.***        | ***LEGAL PROCEEDINGS*** | *** *** |
| *** ***         | *** *** | *** *** |
| ***ITEM  4.***       | ***SUBMISSION  OF MATTERS TO A VOTE OF SECURITY HOLDERS*** | *** *** |
| *** ***         | *** *** | *** *** |
| ***PART  II***       |
| *** ***         | *** *** | *** *** |
| ***ITEM  5.***       | ***MARKET  FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER  PURCHASES OF EQUITY SECURITIES*** | *** *** |
| *** ***         | *** *** | *** *** |
| ***ITEM 6.***        | ***SELECTED FINANCIAL  DATA*** | *** *** |
| *** ***         | *** *** | *** *** |
| ***ITEM  7.***       | ***MANAGEMENT’S  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS*** | *** *** |
| *** ***         | *** *** | *** *** |
| ***ITEM  7A.***      | ***QUALITATIVE  AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK*** | *** *** |
| *** ***         | *** *** | *** *** |
| ***ITEM  8.***       | ***FINANCIAL  STATEMENTS AND SUPPLEMENTARY DATA*** | *** *** |
| *** ***         | *** *** | *** *** |
| ***ITEM  9.***       | ***CHANGES  IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES*** | *** *** |
| *** ***         | *** *** | *** *** |
| ***ITEM 9A.***       | ***CONTROLS AND  PROCEDURES*** | *** *** |
| *** ***         | *** *** | *** *** |
| ***ITEM 9B.***       | ***OTHER INFORMATION*** | *** *** |
| *** ***         | *** *** | *** *** |
| ***PART III***       |
| *** ***         | *** *** | *** *** |
| ***ITEM  10.***      | ***DIRECTORS  AND EXECUTIVE OFFICERS OF THE REGISTRANT*** | *** *** |
| *** ***         | *** *** | *** *** |
| ***ITEM 11.***       | ***EXECUTIVE COMPENSATION*** | *** *** |
| *** ***         | *** *** | *** *** |
| ***ITEM  12.***      | ***SECURITY  OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER  MATTERS*** | *** *** |
| *** ***         | *** *** | *** *** |
| ***ITEM  13.***      | ***CERTAIN  RELATIONSHIPS AND RELATED TRANSACTIONS*** | *** *** |
| *** ***         | *** *** | *** *** |
| ***ITEM  14.***      | ***PRINCIPAL  ACCOUNTANT FEES AND SERVICES*** | *** *** |
| *** ***         | *** *** | *** *** |
| ***PART IV***        |
| *** ***         | *** *** | *** *** |
| ***ITEM  15.***      | ***EXHIBITS  AND FINANCIAL STATEMENT SCHEDULES*** | *** *** |

 

2

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##### **EDGE PETROLEUM CORPORATION**

##### ** **

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

 

**FORWARD LOOKINGINFORMATION**

** **

Certainof the statements contained in all parts of this document (including theportion, if any, to which this Form 10-K is attached), including, but notlimited to, those relating to our drilling plans (including scheduled andbudgeted wells), the effect of changes in strategy and business discipline,future tax matters, our 3-D project portfolio, future general andadministrative expenses on a per unit of production basis, changes in wellsoperated and reserves, future growth and expansion, future exploration, futureseismic data (including timing and results), expansion of operation, ourability to generate additional prospects, review of outside generated prospectsand acquisitions, additional reserves and reserve increases, replace productionand manage our asset base, enhancement of visualization and interpretationstrengths, expansion and improvement of capabilities, integration of newtechnology into operations, credit facilities, redetermination of our borrowingbase, attraction of new members to the technical team, future compensation programs,new focus on core areas, new prospects and drilling locations, new alliances,future capital expenditures (or funding thereof) and working capital,sufficiency of future working capital, borrowings and capital resources andliquidity, projected rates of return, retained earnings and dividend policies,projected cash flows from operations, future commodity price environment,expectation or timing of reaching payout, outcome, effects or timing of anylegal proceedings or contingencies,  theimpact of any change in accounting policies on our financial statements, thenumber, timing or results of any wells, realization of post-closing priceadjustments with respect to the Contango Asset Acquisition, the plans fortiming, interpretation and results of new or existing seismic surveys orseismic data, future production or reserves, future acquisition of leases,lease options or other land rights, management’s assessment of internal controlover financial reporting and our independent registered public accounting firm’sattestation and report on management’s assessment, the identification ofmaterial weaknesses in internal control over financial reporting and any otherstatements regarding future operations, financial results, opportunities,growth, business plans and strategy and other statements that are nothistorical facts are forward looking statements.  These forward-looking statements reflect ourcurrent view of future events and financial performance.  When used in this document, the words “budgeted,”“anticipate,” “estimate,” “expect,” “may,” “project,” “believe,” “intend,” “plan,”“potential,” “forecast,” “might,” “predict,” “should” and similar expressionsare intended to be among the statements that identify forward-lookingstatements. These forward-looking statements speak only as of their dates andshould not be unduly relied upon.  Weundertake no obligation to publicly update or revise any forward-lookingstatement, whether as a result of new information, future events, orotherwise.   Such statements involverisks and uncertainties, including, but not limited to, those set forth under *ITEMS 1 AND 2. “BUSINESS AND PROPERTIES –*RISKFACTORS*”* and other factorsdetailed in this document and our other filings with the Securities andExchange Commission.  Should one or moreof these risks or uncertainties materialize, or should underlying assumptionsprove incorrect, actual outcomes may vary materially from those indicated.  All subsequent written and oralforward-looking statements attributable to the Company or to persons acting onits behalf are expressly qualified in their entirety by reference to theserisks and uncertainties.

 

**PART I**

 

***ITEMS1 AND 2.  BUSINESS AND PROPERTIES***

 

###### **Overview**

###### ** **

EdgePetroleum Corporation is an independent oil and natural gas company engaged inthe exploration, development, acquisition and production of crude oil andnatural gas properties in the United States. Edge was founded in 1983 as aprivate company and went public in 1997 through an initial public offering.  We have evolved over time from a prospectgeneration organization focused on high-risk, high-reward exploration projectsto a team-driven organization focused on a balanced program of exploration,exploitation, development and acquisition of oil and natural gas properties.  Following a top-level management change inlate 1998, a more disciplined style of business planning and management wasintegrated into our technology-driven drilling activities.  We believe the continuation of thisdisciplined business model will result in continued growth in reserves,production and financial strength.

 

3

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# **Recent Developments**

# ** **

At year-end 2004, our netproved reserves were 89.1 Bcfe, comprised of 66.3 billion cubic feet of naturalgas, 1.8 million barrels of natural gas liquids and 2.0 million barrels ofcrude oil and condensate. Natural gas and natural gas liquids accounted forapproximately 86% of those proved reserves. Approximately 75% of total proved reserves were developed as of year-end2004 and they were all located onshore, in the United States. We spent much of2004 (i) developing and exploiting assets acquired late in 2003, includingthose assets involved in our southeast New Mexico exploration alliance enteredinto late in 2003, and (ii) developing our remaining core asset base. Late in2004, we completed a public offering of 3.5 million shares of our common stockand acquired interests in certain south Texas oil and gas properties fromContango Oil & Gas Company (“Contango”). On February 14, 2005, weannounced that we had entered into a new exploration and development venture tojointly explore for oil and natural gas in south Texas with a private oil andgas company. This venture will be called the “Vista Nueva” project and it willgive the Company access to 3-D seismic data covering a portion of its recentlyacquired assets plus undeveloped acreage and an exclusive option to secureleases of unleased minerals in the project area.

 

# **Strategy**

# ** **

Ourbusiness strategy is based on the following six main elements:

 

*Growreserves through the drilling of a balanced portfolio of prospects*

 

Weseek to maintain a prudent balance between higher risk/reward wells and moremoderate risk/reward wells. In 2004, we drilled 49 wells (26.91 net), primarilyin Texas, with 40 of those wells completed as productive for an apparentsuccess rate of approximately 82%. This drilling program, along with ouracquisition of certain oil and gas assets from Contango, helped us to grow ouryear-end reserves by 39% and replaced 308% of our production (see *ITEMS 1 and 2. BUSINESS AND PROPERTIES*- “Oil and NaturalGas Reserve Replacement”). Our drilling program for 2005 is focused primarilyin south Texas, and to a lesser extent in southeastern New Mexico.  We expect to drill between 50 and 55 wells(28 and 31 net, respectively) in 2005 and we estimate capital spending fordrilling for the year to be approximately $50 million.  In addition, we have a contingent drillingprogram that could add up to $20 million to $25 million to thisestimate. Our contingent drilling program is dependent upon certain factors,including success of various related wells, commodity pricing, obtainingcertain leases and the availability of sufficient cash flow from operations toexecute the program without materially increasing our debt.

 

*Balanceexploration risk with the exploitation of existing properties and acquisitionsthat we believe have upside potential*

 

In2004, 56% of our reserve growth came from our drilling activity (which includesadditions, extensions and revisions from new drilling, well work and theaddition of certain proved undeveloped locations) and the remaining 44% camefrom acquisitions. We seek acquisitions of producing properties that typicallyhave exploration or exploitation upside potential. We primarily seek propertiesin our existing core areas, or as a means to establish new core areas. We spentconsiderable effort in 2004 on acquisitions and in December 2004 wesuccessfully closed the Contango Asset Acquisition, the largest acquisition inour history. We continue to work diligently to identify and evaluateacquisition opportunities with the goal of identifying those that we believewould fit our strategic plan and add shareholder value.

 

Webelieve our core drilling program has the potential to replace our productionand to provide moderate reserve growth while our higher-risk drilling programand acquisitions have the potential to rapidly accelerate our growth as well asadd to future drilling opportunities.

 

*Focuson specific geographic areas where we believe we can add value*

 

Webelieve geographic focus is a critical element of success. Long-term successrequires detailed knowledge of both geologic and geophysical attributes, aswell as operating conditions in our chosen areas. As a result, we focus on aselect number of geographic areas where our experience and strengths can beapplied with a significant influence

 

4

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on the outcome. Webelieve this focus will allow us to manage a growing asset base and add valueto additional properties while controlling incremental costs and staffingrequirements.

 

*Integratetechnological advances into our exploration, drilling, production operationsand administration*

 

We useadvanced technologies as risk reduction tools in our exploration, development,drilling and completion activities. Data analysis techniques and advancedprocessing techniques combined with our more traditional sub-surfaceinterpretation techniques allow our team of technical personnel to more easilyidentify features, structural details and fluid contacts, that could beoverlooked using less sophisticated data interpretation techniques. As of December 31,2004, we had rights to approximately 2,470 square miles of 3-D seismic dataprincipally located in Texas, Louisiana and Mississippi.

 

*Maintaina conservative financial structure and control our cost structure*

 

Webelieve that a conservative financial structure is crucial to consistent,positive financial results, management of cyclical swings in our industry andthe ability to move quickly to take advantage of acquisitions and attractivedrilling opportunities. In order to maximize our financial flexibility, we tryto maintain a total debt-to-capital ratio of less than 30%. At December 31,2004, our debt-to-total capital ratio was 11.7%.

 

We tryto fund most of our ongoing capital expenditures from cash flow fromoperations, reserving our debt capacity for potential investment opportunitiesthat we believe can profitably add to our program. Part of a sound financialstructure is constant attention to costs, both operating and overhead costs.Over the past several years, we have worked diligently to control our operatingcosts and overhead costs and instituted a formal, disciplined capital budgetingprocess.  We strive to be creative withthe use of partnerships and alliances so as to leverage capital resources andenhance our ability to meet our objectives.

 

*Useequity ownership and performance based compensation programs to attract andretain a high-quality workforce*

 

Followinga management change in late 1998, we eliminated the previous overriding royaltycompensation system and replaced it with a system designed to reward allemployees through performance-based compensation that is competitive with ourpeers and through equity ownership. As of March 11, 2005, our directorsand executive officers owned or had options to acquire an aggregate ofapproximately 11% of our outstanding common stock.

 

**Employees**

** **

At thetime of this filing, we had 53 full-time employees.  We believe that our relationships with ouremployees are good.  None of ouremployees are covered by a collective bargaining agreement.  From time to time, we utilize the services ofindependent consultants and contractors to perform various professionalservices, particularly in the areas of construction, design, well sitesurveillance, permitting and environmental assessment.  Field and on-site production operationservices, such as pumping, maintenance, dispatching, inspection and testing aregenerally provided by independent contractors.

 

**Offices**

** **

Ourprincipal executive and corporate offices are located in an office buildinglocated in Houston, Texas.  We lease thespace and during the second quarter of 2004 we negotiated a new expanded leaseto accommodate our growing Company.

 

### **Oil and Natural Gas Reserves**

### ** **

Thefollowing table sets forth our estimated net proved oil and natural gasreserves and the present value of estimated future pretax net cash flowsrelated to such reserves as of December 31, 2004.  We engaged Ryder Scott Company (“Ryder Scott”)and W. D. Von Gonten & Co. (“WDVG”) to estimate our net proved reserves,projected future production, estimated future net revenue attributable to our provedreserves, and the present value of such estimated future net revenue as of December 31,2004.  Ryder Scott and WDVG’s estimateswere based upon a

 

5

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review of productionhistories and other geologic, economic, ownership and engineering data providedby us.  Ryder Scott has independentlyevaluated our reserves for the past eleven years and WDVG has independentlyreviewed the reserves we acquired from Contango for the past three years.  In estimating the reserve quantities that areeconomically recoverable, Ryder Scott and WDVG used year-end oil and naturalgas prices in effect at December 31, 2004 and estimated development andproduction costs that were in effect during December 2004 without givingeffect to hedging activities.  Inaccordance with requirements of the Securities and Exchange Commission (the “SEC”)regulations, no price or cost escalation or reduction was considered by RyderScott and WDVG.  For further informationconcerning Ryder Scott and WDVG’s estimates of our proved reserves at December 31,2004, see the reserve reports included as exhibits to this Annual Report onForm 10-K (the “Ryder Scott Report” and the “WDVG Report”).  The present value of estimated future netrevenues before income taxes was prepared using constant prices as of thecalculation date, discounted at 10% per annum on a pretax basis, and is notintended to represent the current market value of the estimated oil and naturalgas reserves owned by us.  For furtherinformation concerning the present value of future net revenue from theseproved reserves, see Note 20 to our consolidated financial statements.  See *ITEMS 1 AND 2. “BUSINESSAND PROPERTIES –*RISK FACTORS*.”*  The oil and natural gas reserve data includedin or incorporated by reference in this document are only estimates and mayprove to be inaccurate.

 
| ** **                                                                                    | ** ** | **Proved Reserves** | ** **  |
|-----------------------------------------------------------------------------------------------|------------|---------------------|-------------|
| ** **                                                                                    | ** ** | **Developed (1)**   | ** **  | **Undeveloped (2)** | ** ** | **Total** | ** ** |
| ** **                                                                                    | ** ** | ** **          | ** **  | ** ** | ** ** | ** ** | ** ** |
| Oil and condensate (MBbls)(3)                                                                 |       | 2,698               |        | 1,094 |   | 3,792 |   |
| Natural gas (MMcf)                                                                            |       | 50,698              |        | 15,613 |   | 66,311 |   |
| Total Mmcfe                                                                                   |       | 66,886              |        | 22,177 |   | 89,063 |   |
|                                                                                          |       |                |        |   |   |   |   |
| Estimated future net revenue before income taxes                                              |       | $                   | 290,766,221 |   | $ | 83,221,295 |   | $ | 373,987,516 |   |
|                                                                                          |       |                |        |   |   |   |   |
| Present value of estimated future net revenue before  income taxes (discounted 10% annum) (4) |       | $                   | 198,322,069 |   | $ | 55,568,791 |   | $ | 253,890,860 |   |
|                                                                                               |            |                     |             |  |  |  |  |  |  |  |  |  |

 

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(1)   Proved developedreserves are proved reserves that are expected to be recovered from existingwells with existing equipment and operating methods.

(2)   Proved undevelopedreserves are proved reserves which are expected to be recovered from new wellson undrilled acreage or from existing wells where a relatively majorexpenditure is required for recompletion.

(3)   Includes naturalgas liquids.

(4)   Estimated futurenet revenue represents estimated future gross revenue to be generated from theproduction of proved reserves, net of estimated future production anddevelopment costs, using year-end NYMEX oil and natural gas prices in effect atDecember 31, 2004, which were $6.18 per MMbtu of natural gas and $43.46per Bbl of oil.

 

Thereserve data set forth herein represents estimates only.  Reserve engineering is a subjective processof estimating underground accumulations of oil and natural gas that cannot bemeasured in an exact manner, and the accuracy of any reserve estimate is afunction of the quality of available data and of engineering and geologicalinterpretation and judgment.  As aresult, estimates made by different engineers often vary from one another.  In addition, results of drilling, testing andproduction subsequent to the date of an estimate may justify revision of suchestimates, and such revisions may be material. Accordingly, reserve estimates are generally different from thequantities of oil and natural gas that are ultimately recovered.  Furthermore, the estimated future net revenuefrom proved reserves and the present value thereof are based upon certainassumptions, including current prices, production levels and costs that may notbe what is actually incurred or realized.

 

Noestimates of proved reserves comparable to those included herein have beenincluded in reports to any federal agency other than the SEC.

 

Inaccordance with SEC regulations, the Ryder Scott Report and the WDVG Reporteach used year-end oil and natural gas prices in effect at December 31,2004.  The prices used in calculating theestimated future net revenue attributable to proved reserves do not necessarilyreflect market prices for oil and natural gas production subsequent to December 31,2004.  There can be no assurance that allof the proved reserves will be produced and sold within the periods indicated,that the assumed prices will actually be realized for such production or thatexisting contracts will be honored or judicially enforced.

 

6

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# **Oil and Natural Gas ReserveReplacement**

 

Findingand developing sufficient amounts of natural gas and crude oil reserves ateconomical costs are critical to the Company’s long-term success. Our business,as with other extractive industries, is a depleting one in which each gasequivalent unit produced must be replaced or we, and a critical source of ourfuture liquidity, will shrink. Given the inherent decline of reserves resultingfrom the production of those reserves, it is important for an exploration andproduction company to demonstrate a long-term trend of more than offsettingproduced volumes with new reserves that will provide for future production.Management uses the reserve replacement ratio, as defined below, as anindicator of the Company’s ability to replenish annual production volumes andgrow its reserves, thereby providing some information on the sources of futureproduction. Managementbelieves that reserve replacement is relevant and useful information that iscommonly used by analysts, investors and other interested parties in the oiland gas industry as a means of evaluating the operational performanceand to a greater extent the prospects of entities engaged in the production andsale of depleting natural resources. These measures are often used as a metricto evaluate an entity’s historical track record of replacing the reserves thatit produced. The reserve replacement ratio is calculated by dividing the sum ofreserve additions from all sources (revisions, purchases, extensions anddiscoveries) by the actual production for the corresponding period. Additions to our reserves are proven developedand proven undeveloped reserves. We expect to continue adding to our reservebase through these activities, but certain factors outside our control mayimpede our ability to do so (see Risk Factors below). The values forthese reserve additions and production are derived directly from the provedreserves table in note 20 to our consolidated financial statements.Accordingly, the Company does not use unproved reserve quantities. It should benoted that the reserve replacement ratio is a statistical indicator that haslimitations. As an annual measure, the ratio is limited because it typicallyvaries widely based on the extent and timing of new discoveries and propertyacquisitions. Its predictive and comparative value is also limited for the samereasons. In addition, since the ratio does not consider the cost or timing offuture production of new reserves, it cannot be used as a measure of valuecreation. The ratio does not distinguish between changes in reserve quantitiesthat are developed and those that will require additional time and funding todevelop.  In that regard, it might benoted that percentage of reserves that were developed was 75%, 78%, and 68% forthe years ended December 31, 2004, 2003 and 2002, respectively.  Set forth below is our reserve replacementratio for the years ended December 31, 2004, 2003 and 2002.

 
| ** **                | ** ** | **For the year ended  December 31,** | ** ** | **Three year** | ** ** |
|---------------------------|------------|-------------------------------------------|------------|----------------|------------|
| ** **                | ** ** | **2004**                                  | ** ** | **2003**       | ** ** | **2002** | ** ** | **Average** | ** ** |
| Reserve Replacement Ratio |       | 308%                                      |       | 285%           |       | 161% |   | 263% |   |

 

# **Oil and Natural GasVolumes, Prices and Operating Expense**

# ** **

Thefollowing table sets forth certain information regarding production volumes,average sales prices and average operating expense associated with our sale ofoil and natural gas for the periods indicated.

 
| ** **                                                                                                         | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                                         | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| **Production:**                                                                                                    |       |                             |       |   |   |   |   |
| Oil and condensate (MBbls)                                                                                         |       | 215                              |       | 123 |   | 120 |   |
| Natural gas liquids (MBbls)                                                                                        |       | 276                              |       | 178 |   | 161 |   |
| Natural gas (MMcf)                                                                                                 |       | 9,148                            |       | 6,290 |   | 5,266 |   |
| Natural gas equivalent (MMcfe)                                                                                     |       | 12,093                           |       | 8,093 |   | 6,951 |   |
| **Average Sales Price - before hedging and  derivatives:**                                                         |       |                             |       |   |   |   |   |
| Oil and condensate ($ per Bbl)                                                                                |       | $                                | 39.77      |   | $ | 31.48 |   | $ | 22.88 |   |
| Natural gas liquids ($ per Bbl)                                                                               |       | $                                | 15.83      |   | $ | 12.37 |   | $ | 10.31 |   |
| Natural gas ($ per Mcf)                                                                                       |       | $                                | 5.91       |   | $ | 5.14 |   | $ | 3.20 |   |
| Natural gas equivalent ($ per Mcfe)                                                                           |       | $                                | 5.54       |   | $ | 4.74 |   | $ | 3.06 |   |
| **Average Sales Price - after hedging and  derivatives:**                                                          |       |                             |       |   |   |   |   |
| Oil and condensate ($ per Bbl)                                                                                |       | $                                | 33.03      |   | $ | 31.48 |   | $ | 22.88 |   |
| Natural gas liquids ($ per Bbl)                                                                               |       | $                                | 15.83      |   | $ | 12.37 |   | $ | 10.31 |   |
| Natural gas ($ per Mcf)                                                                                       |       | $                                | 5.80       |   | $ | 4.43 |   | $ | 3.14 |   |
| Natural gas equivalent ($ per Mcfe)                                                                           |       | $                                | 5.33       |   | $ | 4.19 |   | $ | 3.01 |   |
|                                                                                                               |       |                             |       |   |   |   |   |
| **Average oil and natural gas operating expenses  including production and ad valorem taxes ($ per Mcfe)(1)** |       | $                                | 0.77       |   | $ | 0.63 |   | $ | 0.55 |   |

 

7

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(1)   Includes directlifting costs (labor, repairs and maintenance, materials and supplies),expensed workover costs and the administrative costs of field productionpersonnel, insurance and production and ad valorem taxes.

 

**Exploration, Development and Acquisition CapitalExpenditures**

** **

Thefollowing table sets forth certain information regarding the total costsincurred associated with exploration, development and acquisition activities.

 
| ** **                 | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------|------------|----------------------------------|------------|
| ** **                 | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                 | ** ** | **(in thousands)**               | ** ** |
| Acquisition costs:         |       |                             |       |   |   |   |   |
| Unproved properties        |       | $                                | 12,163     |   | $ | 6,052 |   | $ | 5,466 |   |
| Proved properties          |       | 33,980                           |       | 10,374 |   | 1,369 |   |
| Exploration costs          |       | 8,297                            |       | 6,017 |   | 4,725 |   |
| Development costs          |       | 34,548                           |       | 12,271 |   | 7,927 |   |
| Subtotal                   |       | 88,988                           |       | 34,714 |   | 19,487 |   |
| Asset retirement costs (1) |       | 278                              |       | 898 |   | — |   |
| Total costs incurred       |       | $                                | 89,266     |   | $ | 35,612 |   | $ | 19,487 |   |

 

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(1)          Excludedfrom asset retirement costs in 2003 was $640,400 related to the cumulativeeffect of the adoption of SFAS No. 143 on January 1, 2003.  See Note 7 to our consolidated financialstatements.

 

Netcosts incurred excludes sales of proved oil and natural gas properties whichare accounted for as adjustments of capitalized costs with no gain or lossrecognized, unless such adjustments would significantly alter the relationshipbetween capitalized costs and proved reserves.

 

**Drilling Activity**

** **

Thefollowing table sets forth our drilling activity for the three years ended December 31,2004.  In the table, “Gross” refers tothe total wells in which we have a working interest or back-in working interestafter payout and “Net” refers to gross wells multiplied by our working interesttherein.

 
| ** **       | ** ** | **For the Year Ended December 31,** | ** ** |
|------------------|------------|------------------------------------------|------------|
| ** **       | ** ** | **2004**                                 | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **       | ** ** | **Gross**                                | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Exploratory:** |       |                                     |       |   |   |   |   |   |   |   |   |   |   |
| Productive       |       | 5                                        |       | 2.35 |   | 10 |   | 7.05 |   | 4 |   | 3.45 |   |
| Non-productive   |       | 5                                        |       | 2.50 |   | 8 |   | 4.25 |   | — |   | — |   |
| Total            |       | 10                                       |       | 4.85 |   | 18 |   | 11.30 |   | 4 |   | 3.45 |   |
| **Development:** |       |                                     |       |   |   |   |   |   |   |   |   |   |   |
| Productive       |       | 35                                       |       | 19.33 |   | 18 |   | 6.62 |   | 7 |   | 2.69 |   |
| Non-productive   |       | 4                                        |       | 2.73 |   | — |   | — |   | 2 |   | 0.54 |   |
| Total            |       | 39                                       |       | 22.06 |   | 18 |   | 6.62 |   | 9 |   | 3.23 |   |
| **Grand Total**  |       | 49                                       |       | 26.91 |   | 36 |   | 17.92 |   | 13 |   | 6.68 |   |

 

# **Productive Wells**

# ** **

Thefollowing table sets forth the number of productive oil and natural gas wellsin which we owned an interest as of December 31, 2004.

 

8

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| ** **  | ** ** | **Company-Operated** | ** ** | **Non-Operated** | ** ** | **Total** | ** ** |
|-------------|------------|----------------------|------------|------------------|------------|-----------|------------|
| ** **  | ** ** | **Gross**            | ** ** | **Net**          | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|        |       |                 |       |             |       |      |       |   |   |   |   |   |   |
| Oil         |       | 14                   |       | 8.56             |       | 54        |       | 16.93 |   | 68 |   | 25.49 |   |
| Natural gas |       | 89                   |       | 71.37            |       | 160       |       | 51.37 |   | 249 |   | 122.74 |   |
| Total       |       | 103                  |       | 79.93            |       | 214       |       | 68.30 |   | 317 |   | 148.23 |   |

 

# **Acreage Data**

# ** **

Thefollowing table sets forth certain information regarding our developed andundeveloped lease acreage as of December 31, 2004.  Developed acres refer to acreage withinproducing units and undeveloped acres refer to acreage that has not been placedin producing units.

 
| ** **  | ** ** | **Developed Acres** | ** ** | **Undeveloped Acres** | ** ** | **Total** | ** ** |
|-------------|------------|---------------------|------------|-----------------------|------------|-----------|------------|
| ** **  | ** ** | **Gross**           | ** ** | **Net**               | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|        |       |                |       |                  |       |      |       |   |   |   |   |   |   |
| Montana     |       | —              |       | —                |       | 17,715    |       | 11,658 |   | 17,715 |   | 11,658 |   |
| Michigan    |       | 160                 |       | 160                   |       | 498       |       | 498 |   | 658 |   | 658 |   |
| Alabama     |       | 536                 |       | 3                     |       | 40        |       | 1 |   | 576 |   | 4 |   |
| Louisiana   |       | 3,307               |       | 726                   |       | 3,423     |       | 435 |   | 6,730 |   | 1,161 |   |
| New Mexico  |       | 3,448               |       | 1,337                 |       | 94,310    |       | 18,135 |   | 97,758 |   | 19,472 |   |
| Mississippi |       | 8,962               |       | 3,193                 |       | 2,989     |       | 1,233 |   | 11,951 |   | 4,426 |   |
| Texas       |       | 59,588              |       | 25,905                |       | 15,176    |       | 4,291 |   | 74,764 |   | 30,196 |   |
| Total       |       | 76,001              |       | 31,324                |       | 134,151   |       | 36,251 |   | 210,152 |   | 67,575 |   |

 

Leasescovering approximately 4,679 gross (2,695 net), 6,715 gross (1,964 net) and12,769 gross (8,722 net) undeveloped acres are scheduled to expire in 2005,2006 and 2007, respectively.  In general,our leases will continue past their primary terms if oil and natural gasproduction in commercial quantities is being produced from a well on suchlease.

 

### **The table does not include (i) 80,000 gross (68,000**net) acres that we have a right to acquire onor before July 26, 2005 pursuant to an Indian Mineral DevelopmentAgreement with the Blackfeet Indian Tribe or (ii) 1,300 gross (325 net) acresin Louisiana that we have the right to acquire on or before October 20,2005.

### ** **

# **Core Areas of Operation**

# ** **

As of December 31,2004, 77.1% of our proved reserves were in south Texas, 10.7% in southLouisiana and 12.2% in New Mexico, Michigan, Mississippi and Alabama.  During 2004, we added reserves and productionin our new core area in southeastern New Mexico, as a result of an explorationand development alliance entered into in late 2003 and as a result of theContango Asset Acquisition.

 

Thetable below sets forth the gross and net number of our gas and oil wells ineach of our core areas of operation as of December 31, 2004.

 
| ** **  | ** ** | **Gas Wells** | ** ** | **Oil Wells** | ** ** |
|-------------|------------|---------------|------------|---------------|------------|
| ** **  | ** ** | **Gross**     | ** ** | **Net**       | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Texas       |       | 222           |       | 111.95        |       | 40 |   | 18.23 |   |
| Louisiana   |       | 7             |       | 1.40          |       | — |   | — |   |
| Mississippi |       | 13            |       | 5.47          |       | 18 |   | 3.73 |   |
| Alabama     |       | 1             |       | —        |       | 4 |   | 0.22 |   |
| Michigan    |       | 1             |       | 1.00          |       | — |   | — |   |
| New Mexico  |       | 4             |       | 2.42          |       | 7 |   | 3.81 |   |
| Total       |       | 248           |       | 122.24        |       | 69 |   | 25.99 |   |

 

9

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# ***Texas***

# ** **

Wecurrently own an interest in 74,764 gross (30,196 net) acres in south andsouth-central Texas.  Our areas of focusin this region are predominantly in the Wilcox (Lobo), Queen City, Yegua,Vicksburg and Frio producing trends.  Asof December 31, 2004, we operated approximately 88 producing wells,accounting for about 77% of our total net production in Texas.  We drilled 32 wells during 2004 in Texas, 26of which were successfully completed. The majority of our 2004 drilling activity took place at the Gato Creek(Lobo), and Encinitas (Vicksburg) Project Areas.  We drilled eight successful wells at GatoCreek and installed additional compression to improve productionperformance.  Twelve successful wellswere drilled in the Encinitas Field in 2004. In 2005, we currently expect to drill 30 to 35 wells (20.5 to 25.5 net,respectively) in our core areas in Texas. The majority of these wells are planned in the Gato Creek area, theEncinitas Field, and in a new Queen City project area in Jim Hogg County.

 

We made one cash assetacquisition in Texas during 2004.  Theacquisition added to our existing position, notably in the Queen City trend inJim Hogg County, Texas (see Note 6 to our consolidated financial statements).

 

# ***Louisiana***

# ** **

Wecurrently own an interest in 6,730 gross (1,161 net) acres in southLouisiana.  Our operations in this areahave been focused in the prolific gas-producing region covering portions ofAcadia, Calcasieu, Lafayette, St. Landry and Vermilion Parishes.  As of December 31, 2004, we had aninterest in seven wells, none of which we operate. One exploratory well wasdrilled in Calcasieu Parish in late 2004, and was a dry hole. We currently haveplans to participate with a 25% working interest in up to two 13,000-footexploratory tests in 2005.  These wellswill be located in Calcasieu Parish in southwest Louisiana and will target theFrio age Hackberry sands.  We also planto drill a development well offsetting the Thibodeaux #1 ST well located inLafayette Parish.

 

# ***Mississippi***

# ** **

Wecurrently own an interest in 11,951 gross (4,426 net) acres inMississippi.  We acquired additionalreserves and production in the Mississippi Salt Basin in south centralMississippi as part of the 2003 merger with Miller Exploration Company (“Miller”).  The primary producing horizons in theMississippi Salt Basin around the Miller properties include the Hosston, Sligo,Rodessa and James Lime sections.  As of December 31,2004, we operated nine producing wells, accounting for about 83% of our totalnet production in Mississippi. In 2004 we completed a Lower Hosston well atCenterville Dome, and acquired 3-D seismic over Midway Dome. In 2005, we planto acquire additional 3-D seismic and could drill one to two wells (0.9 to 1.1net) in this area.

 

# ***Michigan***

# ** **

Wecurrently own an interest in 658 gross (658 net) acres in Michigan.  We acquired acreage and one producing well insouth central Michigan as part of the 2003 merger with Miller.  This well is operated by Edge and producesfrom the Trenton/Black River formation at approximately 3,000 feet.  We have no plans for additional activity inMichigan in 2005 at this time.

 

# ***New Mexico/West Texas-Permian Basin***

# ** **

Weestablished a new core area in southeastern New Mexico through an alliance withtwo private companies in 2003.  Wecurrently own an interest in 97,758 gross (19,472 net) acres in this area thatwe earned through a drilling obligation that we fulfilled in 2004. Theobjectives in this area are shallow oil in the Yeso, San Andres, Queen andGrayburg formations, and deep gas in the Atoka and Morrow formations.Additional objectives are the Strawn, Cisco, Wolfcamp and Devonian formations.In 2004, we participated in the drilling of seven (3.7 net) shallow and eight(3.9 net) deep wells. All of the shallow wells and six of the deep wells werecompleted successfully. We also acquired an additional 2,381 gross (1,557 net)acres from Federal and State lease sales. During 2005, we anticipate drillingapproximately 13 (3.8 net) wells in New Mexico, and also anticipate adding toour acreage position in this area through lease sale acquisitions.

 

10

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# ***Northern Rocky Mountains***

# ** **

We currentlyown an interest in 4,905 gross (1,352 net) undeveloped acres in the northernPowder River Basin of Montana and also own an interest in 12,810 gross (10,306net) undeveloped acres as well as an option on 80,000 gross (68,000 net) acresin north central Montana on a portion of the Blackfeet Indian Reservation.  Our option on the Blackfeet IndianReservation was acquired as part of the 2003 merger with Miller. In the eventthat we do not pay the annual rental of $100,000 by July 26, 2005, ouroption on the Blackfeet Indian Reservation will terminate. We have no currentplans for drilling in the Powder River Basin or on the Blackfeet IndianReservation.

 

###### **Title to Properties**

###### ** **

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

 

Wehave granted mortgage liens on substantially all of our oil and natural gasproperties in favor of Union Bank of California, as agent, to secure our creditfacility.  These mortgages and the creditfacility contain substantial restrictions and operating covenants that arecustomarily found in loan agreements of this type.  See *ITEM7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OFOPERATIONS* – LIQUIDITY AND CAPITAL RESOURCES – *CREDIT FACILITY”* and Note 10 to ourconsolidated financial statements.

 

###### **Marketing**

###### ** **

Ourproduction is marketed to third parties consistent with industry practices. Wemarket our own production where feasible, but on occasion engage a third-partymarketing agent. Typically, oil is sold at the well-head at field-posted pricesand natural gas is sold under contract at a negotiated monthly price based uponfactors normally considered in the industry, such as conditioning or treatingto make gas marketable, distance from the well to the transportation pipeline,well pressure, estimated reserves, quality of natural gas and prevailingsupply/demand conditions.

 

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

 

Thereare a variety of factors which affect the market for oil and natural gas,including the extent of domestic production and imports of oil and natural gas,the proximity and capacity of natural gas pipelines and other transportationfacilities, demand for oil and natural gas, the marketing of competitive fuelsand the effects of state and federal regulations on oil and natural gasproduction and sales.  We have notexperienced any significant difficulties in marketing our oil and natural gas.The oil and natural gas industry also competes with other industries insupplying the energy and fuel requirements of industrial, commercial andindividual customers.

 

Wherefeasible, we use a combination of market-sensitive pricing and forward-fixedpricing.  Forward pricing is utilized totake advantage of anomalies in the futures market and to hedge a portion of ourproduction at prices exceeding forecast. All such hedging transactions provide for financial rather than physicalsettlement. See *ITEM 7. “MANAGEMENT’S DISCUSSION ANDANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS –*CRITICAL ACCOUNTING POLICIESAND ESTIMATES – DERIVATIVES AND HEDGING ACTIVITIES*.”*

 

Due tothe instability of oil and natural gas prices, we may enter into, from time totime, price risk management transactions (e.g., swaps, collars and floors) fora portion of our oil and natural gas production to

 

11

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achieve a morepredictable cash flow, as well as to reduce exposure from pricefluctuations.  While the use of thesearrangements limits our ability to benefit from increases in the price of oiland natural gas, it also reduces our potential exposure to adverse pricemovements.  Our price risk managementarrangements, to the extent we enter into any, apply to only a portion of ourproduction, provide only partial price protection against declines in oil andnatural gas prices and limit our potential gains from future increases inprices.  On a quarterly basis, ourmanagement sets all of our price risk management transaction policies,including volumes, accounting treatment, types of instruments and counterparties. These policies are implemented by management through the execution oftrades by the Chief Financial Officer after consultation with and concurrenceby the President and Chairman of the Board. Our Board of Directors reviews our price risk management policies andtrades.  We account for thesetransactions as hedging and derivative activities and, accordingly, certaingains and losses are included in revenue during the period the transactionsoccur (see Note 9 to our consolidated financial statements).

 

Although we takesome measures to attempt to control price risk, we remain subject to pricefluctuations for natural gas sold in the spot market due primarily toseasonality of demand and other factors beyond our control.  Domestic oil prices generally follow worldwideoil prices, which are subject to price fluctuations resulting from changes inworld supply and demand.  We continue toevaluate the potential for reducing these risks by entering into hedgetransactions.  Included within totalrevenue for the years ended December 31, 2004, 2003, and 2002 wasapproximately $2.5 million, $4.5 million and $0.3 million, respectively,representing net losses from hedging and derivative activity as shown in thetable below.

 
| ** **                                               | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                               | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                               | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Natural gas hedging contract settlements                 |       | $                                | (328,500   | ) | $ | (4,455,590 | ) | $ | (326,950 | ) |
| Crude oil derivative contract settlements                |       | (880,765                         | )          | — |   | — |   |
| Hedge premium reclassification                           |       | (686,250                         | )          | — |   | — |   |
| Oil derivative contract unrealized change in fair  value |       | (564,548                         | )          | — |   | — |   |
|                                                     |       |                             |       |   |   |   |   |
| Loss on hedging and derivatives                          |       | $                                | (2,460,063 | ) | $ | (4,455,590 | ) | $ | (326,950 | ) |

 

The table belowsummarizes the Company’s outstanding hedge and derivative contracts reflectedon the balance sheet at December 31, 2004 and 2003.

 
| ** **              | ** ** | ** **             | ** ** | ** **    | ** ** | ** ** | ** ** | ** **    | ** ** | ** **  | ** ** | **Fair Value of Outstanding Hedging and  Derivative Contracts as of** | ** ** |
|-------------------------|------------|------------------------|------------|---------------|------------|------------|------------|---------------|------------|-------------|------------|-----------------------------------------------------------------------|------------|
| ** **              | ** ** | ** **             | ** ** | ** **    | ** ** | ** ** | ** ** | **Price**     | ** ** | **Volumes** | ** ** | **December 31,**                                                 | ** ** |
| **Transaction  Date**   | ** ** | **Transaction Type**   | ** ** | **Beginning** | ** ** | **Ending** | ** ** | **Per Unit**  | ** ** | **Per Day** | ** ** | **2004 (5)**                                                          | ** ** | **2003** | ** ** |
| ***Natural  Gas (1):*** | ** ** | ** **             | ** ** | ** **    | ** ** | ** ** | ** ** | ** **    | ** ** | ** **  |       |                                                                  |       |   |   |
| 12/03                   |       | Natural Gas Collar     |       | 01/01/2004    |       | 03/31/2004 |       | $4.50-$7.05   |       | 5,000MMbtu  |       | $                                                                     | —     |   | $ | 37,688 |   |
| 08/03                   |       | Natural Gas Collar     | (2)        | 01/01/2004    |       | 03/31/2004 |       | $4.50-$7.00   |       | 10,000MMbtu |       | —                                                                |       | (91,504 | ) |
| 08/03                   |       | Natural Gas Collar     | (2)        | 04/01/2004    |       | 09/30/2004 |       | $4.50-$6.00   |       | 10,000MMbtu |       | —                                                                |       | 42,996 |   |
| 08/03                   |       | Natural Gas Collar     | (2)        | 10/01/2004    |       | 12/31/2004 |       | $4.50-$7.00   |       | 10,000MMbtu |       | —                                                                |       | 131,621 |   |
| 05/04                   |       | Natural Gas Collar     |       | 01/01/2005    |       | 03/31/2005 |       | $5.00-$10.39  |       | 10,000MMbtu |       | 92,703                                                                |       | — |   |
| 07/04                   |       | Natural Gas Collar     |       | 04/01/2005    |       | 06/30/2005 |       | $5.00-$7.53   |       | 10,000MMbtu |       | 9,162                                                                 |       | — |   |
| 07/04                   |       | Natural Gas Collar     |       | 07/01/2005    |       | 09/30/2005 |       | $5.00-$7.67   |       | 10,000MMbtu |       | (41,210                                                               | )          | — |   |
| 10/04                   |       | Natural Gas Collar     |       | 01/01/2005    |       | 12/31/2005 |       | $6.00-$9.52   |       | 10,000MMbtu |       | 1,860,375                                                             |       | — |   |
| ***Crude  Oil (3):***   |       |                   |       |          |       |       |       |          |       |        |       |                                                                  |       |   |   |
| 03/04                   |       |  Crude Oil Collar |       | 04/01/2004    |       | 12/31/2004 |       | $30.00-$35.50 |       | 400Bbl      |       | (96,240                                                               | )          | — |   |
| 05/04 (08/04)           |       |  Crude Oil Collar | (4)        | 01/01/2005    |       | 12/31/2005 |       | $35.00-$40.00 |       | 200/290Bbl  |       | (468,308                                                              | )          | — |   |
|                    |       |                   |       |          |       |       |       |          |       |        |       |                                                                  |       |   |   |   |
|                    |       |                   |       |          |       |       |       |          |       |        |       | $                                                                     | 1,356,482  |   | $ | 120,801 |   |
|                         |            |                        |            |               |            |            |            |               |            |             |            |                                                                       |            |  |  |  |  |  |  |

 

12

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(1)                The Company’scurrent hedging activities for natural gas were entered into on a per MMbtudelivered price basis, using the Houston Ship Channel Index, with settlementfor each calendar month occurring five business days following the expirationdate.

(2)                Thiscontract was entered into at a cost of $686,250.

(3)                Hedgeaccounting is not applied to the Company’s collars on crude oil, which were enteredinto on a per barrel delivered price basis, using the West Texas IntermediateIndex, with settlement for each calendar month occurring five business daysfollowing the expiration date. The change in fair value is reflected in totalrevenue for the year ended December 31, 2004.

(4)                InAugust 2004, the Company replaced the contract that was entered into May2004 with a new contract that changes the volume and pricing terms. The putoption is on 200 Bbl/D and the call option is on 290 Bbl/D. This transactionwas completed at no additional cost to the Company.

(5)                Thefair value of the Company’s outstanding transactions is presented on thebalance sheet by counterparty. Our counterparties net our positions with them,but we cannot present the net of the two counterparty positions because we donot have legal right of offset. Therefore one counterparty is presented in theDerivative Asset and one is presented in the Derivative Liability. The crudeoil collar with a balance of ($468,308) is presented as a liability and theremaining contracts are presented as an asset. All contracts are consideredcurrent.

 

# **Sales to Major Customers**

# ** **

Wesold natural gas and crude oil production representing 10% or more of our totalrevenues for the years ended December 31, 2004, 2003, and 2002 as listedbelow.

 

 
| ** **                   | ** ** | **For the year ended December 31,** | ** ** |
|------------------------------|------------|------------------------------------------|------------|
| **Major Purchaser**          | ** ** | **2004**                                 | ** ** | **2003** | ** ** | **2002** | ** ** |
| Upstream Energy Services (1) |       | 22                                       | %          |   | 38 | % |   | 24 | % |   |
| ChevronTexaco                |       | 22                                       | %          |   | 6 | % |   | 18 | % |   |
| Copano Field Services        |       | 19                                       | %          |   | 16 | % |   | 17 | % |   |
| BTA                          |       | 2                                        | %          |   | 18 | % |   | 5 | % |   |
| Southwestern Energy          |       | 1                                        | %          |   | 5 | % |   | 15 | % |   |

 

----

NOTE:Amounts disclosed are approximations and those that are less than 10% arepresented for information and comparison purposes only. Also these percentagesdo not consider the effects of financial hedges.

 

(1) Upstreamis an agent that sells our production to other purchasers on our behalf.

 

In theexploration, development and production business, production is normally soldto relatively few customers. Substantially all of the Company’s customers areconcentrated in the oil and gas industry, and revenue can be materiallyaffected by current economic conditions and the price of certain commoditiessuch as natural gas and crude oil, the cost of which is passed through to thecustomer. However, based on the current demand for natural gas and crude oiland the fact that alternate purchasers are readily available, we believe thatthe loss of any of our major purchasers would not have a long-term materialadverse effect on our operations.

 

### **Competition**

### ** **

Weencounter competition from other oil and natural gas companies in all areas ofour operations, including the acquisition of exploratory prospects and provenproperties.  Our ability to explore foroil and natural gas reserves and to acquire additional properties in the futurewill be dependent upon our ability to conduct our operations, to evaluate andselect suitable properties and to consummate transactions in this highlycompetitive environment.  We believe thatour technological expertise, our exploration, land, drilling and productioncapabilities and the experience of our management generally enable us tocompete effectively. (See ITEMS 1 AND2. “BUSINESS AND PROPERTIES – RISK FACTORS – We face strong competition fromlarger oil and natural gas companies.”)

 

###### **INDUSTRY REGULATIONS**

###### ** **

 The availability of a ready market for oil andnatural gas production depends upon numerous factors beyond our control.  These factors include regulation of oil andnatural gas production, federal and state regulations governing environmentalquality and pollution control, state limits on allowable rates of production bywell or proration unit, the amount of oil and natural gas available for sale,the availability of adequate pipeline and other transportation and processingfacilities and the marketing of competitive fuels.  For example, a productive natural

 

13

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gas well may be “shut-in”because of an oversupply of natural gas or lack of an available natural gaspipeline in the areas in which we may conduct operations.  State and federal regulations generally areintended to prevent waste of oil and natural gas, protect rights to produce oiland natural gas between owners in a common reservoir, control the amount of oiland natural gas produced by assigning allowable rates of production and controlcontamination of the environment. Pipelines are subject to the jurisdiction of various federal, state andlocal agencies.  We are also subject tochanging and extensive tax laws, the effects of which cannot be predicted.  The following discussion summarizes theregulation of the United States oil and natural gas industry.  We believe that we are in substantialcompliance with the various statutes, rules, regulations and governmentalorders to which our operations may be subject, although there can be noassurance that this is or will remain the case. Moreover, such statutes, rules, regulations and government orders may bechanged or reinterpreted from time to time in response to economic or politicalconditions, and there can be no assurance that such changes orreinterpretations will not materially adversely affect our results ofoperations and financial condition.  Thefollowing discussion is not intended to constitute a complete discussion of thevarious statutes, rules, regulations and governmental orders to which ouroperations may be subject.

 

*Regulationof Oil and Natural Gas Exploration and Production.*  Our operations are subject to various typesof regulation at the federal, state and local levels.  Such regulation includes requiring permitsfor the drilling of wells, maintaining bonding requirements in order to drillor operate wells and regulating the location of wells, the method of drillingand casing wells, the surface use and restoration of properties upon whichwells are drilled, the plugging and abandoning of wells and the disposal offluids used in connection with operations. Our operations are also subject to various conservation laws andregulations.  These include theregulation of the size of drilling and spacing units or proration units and thedensity of wells that may be drilled in and the unitization or pooling of oiland natural gas properties.  In thisregard, some states allow the forced pooling or integration of tracts to facilitateexploration while other states rely primarily or exclusively on voluntarypooling of lands and leases.  In areaswhere pooling is voluntary, it may be more difficult to form units, andtherefore more difficult to develop a project, if the operator owns less than100 percent of the leasehold.  Inaddition, state conservation laws establish maximum rates of production fromoil and natural gas wells, generally prohibit the venting or flaring of naturalgas and impose certain requirements regarding the ratability ofproduction.  The effect of theseregulations may limit the amount of oil and natural gas we can produce from ourwells and may limit the number of wells or the locations at which we can drill.  The regulatory burden on the oil and naturalgas industry increases our costs of doing business and, consequently, affectsour profitability.  Inasmuch such lawsand regulations are frequently expanded, amended and interpreted, we are unableto predict the future cost or impact of complying with such regulations.

 

*Regulationof Sales and Transportation of Natural Gas*.   Federal legislation and regulatory controlshave historically affected the price of natural gas produced by us, and themanner in which such production is transported and marketed.  Under the Natural Gas Act (“NGA”) of 1938,the Federal Energy Regulatory Commission (the “FERC”) regulates the interstatetransportation and the sale in interstate commerce for resale of naturalgas.  Effective January 1, 1993,the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”) deregulatednatural gas prices for all “first sales” of natural gas, including all sales byus of our own production.  As a result,all of our domestically produced natural gas may now be sold at market prices,subject to the terms of any private contracts that may be in effect.  However, the Decontrol Act did not affect theFERC’s jurisdiction over natural gas transportation.

 

Ournatural gas sales are affected by intrastate and interstate gas transportationregulation.  Following the Congressionalpassage of the NGPA, the FERC adopted a series of regulatory changes that havesignificantly altered the transportation and marketing of natural gas.  Beginning with the adoption of Order No. 436,issued in October 1985, the FERC has implemented a series of majorrestructuring orders that have required pipelines, among other things, toperform “open access” transportation of gas for others, “unbundle” their salesand transportation functions, and allow shippers to release their unneeded capacitytemporarily and permanently to other shippers. As a result of these changes,sellers and buyers of gas have gained direct access to the particular pipelineservices they need and are better able to conduct business with a larger numberof counterparties.  We believe thesechanges generally have improved our access to markets while, at the same time,substantially increasing competition in the natural gas marketplace.  It remains to be seen, however, what effectthe FERC’s other activities will have on access to markets, the fostering ofcompetition and the cost of doing business. We cannot predict what new or different regulations the FERC and otherregulatory agencies may adopt, or what effect subsequent regulations may haveon our activities.  We do not believethat we will be affected by any such new or different regulations materiallydifferently than any other seller of natural gas with which we compete.

 

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In thepast, Congress has been very active in the area of gas regulation.  However, as discussed above, the more recenttrend has been in favor of deregulation, or “lighter handed” regulation, andthe promotion of competition in the gas industry.  There regularly are other legislativeproposals pending in the Federal and state legislatures that, if enacted, wouldsignificantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any,might actually be enacted by Congress or the various state legislatures andwhat effect, if any, such proposals might have on us.  Similarly, and despite the trend towardfederal deregulation of the natural gas industry, whether or to what extentthat trend will continue, or what the ultimate effect will be on our sales ofgas, cannot be predicted.  Again, we donot believe that we will be affected by any such new legislative proposalsmaterially differently than any other seller of natural gas with which wecompete.

 

We owncertain natural gas pipelines that we believe meet the standards the FERC hasused to establish a pipeline’s status as a gatherer not subject to FERCjurisdiction under the NGA.  Stateregulation of gathering facilities generally includes various safety,environmental, and in some circumstances, nondiscriminatory take requirements,but does not generally entail rate regulation. Natural gas gathering may receive greater regulatory scrutiny at bothstate and federal levels in the post-restructuring environment.

 

*Oil PriceControls and Transportation Rates.*  Sales of crude oil, condensate and gasliquids by us are not currently regulated and are made at market prices.  The price we receive from the sale of theseproducts may be affected by the cost of transporting the products to market.Much of the transportation is through interstate common carrier pipelines.  Effective as of January 1, 1995, theFERC implemented regulations generally grandfathering all previously approvedinterstate transportation rates and establishing an indexing system for thoserates by which adjustments are made annually based on the rate of inflation,subject to certain conditions and limitations. These regulations have generally been approved on judicial review.  Every five years, the FERC must examine therelationship between the annual change in the applicable index and the actualcost changes experienced in the oil pipeline industry.  The first such review was completed in 2000,and on December 14, 2000, FERC reaffirmed the current index.   The FERC’s regulation of oil transportationrates may tend to increase the cost of transporting oil and natural gas liquidsby interstate pipelines, although the annual adjustments may result indecreased rates in a given year. Following a successful court challenge of these orders by an associationof oil pipelines on February 24, 2003, the FERC acting on remand increasedthe index slightly for the current five-year period, effective July 2001.  We are not able at this time to predict theeffects of these regulations, if any, on the transportation costs associatedwith oil production from our oil producing operations.

 

*EnvironmentalRegulations.*  Ouroperations are subject to numerous federal, state and local laws andregulations governing the discharge of materials into the environment or otherwiserelating to environmental protection. These laws and regulations may require the acquisition of a permitbefore drilling commences, restrict the types, quantities and concentration ofvarious substances that can be released into the environment in connection withdrilling and production activities, limit or prohibit drilling activities oncertain lands within wilderness, wetlands and other protected areas, requireremedial measures to mitigate pollution from former operations, such as pitclosure and plugging abandoned wells, and impose substantial liabilities forpollution resulting from production and drilling operations.  Public interest in the protection of theenvironment has increased dramatically in recent years.  The trend of more expansive and stricterenvironmental legislation and regulations applied to the oil and natural gasindustry could continue, resulting in increased costs of doing business andconsequently affecting profitability.  Tothe extent laws are enacted or other governmental action is taken thatrestricts drilling or imposes more stringent and costly waste handling,disposal and cleanup requirements, our business and prospects could beadversely affected.

 

Wegenerate wastes that may be subject to the federal Resource Conservation andRecovery Act (“RCRA”) and comparable state statutes.  The U.S. Environmental Protection Agency (“EPA”)and various state agencies have limited the approved methods of disposal forcertain hazardous and nonhazardous wastes. Furthermore, certain wastes generated by our oil and natural gasoperations that are currently exempt from treatment as “hazardous wastes” mayin the future be designated as “hazardous wastes,” and therefore be subject tomore rigorous and costly operating and disposal requirements.

 

Wecurrently own or lease numerous properties that for many years have been usedfor the exploration and production of oil and natural gas.  Although we believe that we have used goodoperating and waste disposal practices, prior owners and operators of theseproperties may not have used similar practices, and hydrocarbons or

 

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other wastes may havebeen disposed of or released on or under the properties owned or leased by usor on or under locations where such wastes have been taken for disposal.  In addition, many of these properties havebeen operated by third parties whose treatment and disposal or release ofhydrocarbons or other wastes was not under our control.  These properties and the wastes disposedthereon may be subject to the Comprehensive Environmental Response,Compensation and Liability Act (“CERCLA”), RCRA and analogous state laws aswell as state laws governing the management of oil and natural gas wastes.  Under such laws, we could be required toremove or remediate previously disposed wastes (including wastes disposed of orreleased by prior owners or operators) or property contamination (includinggroundwater contamination) or to perform remedial plugging operations toprevent future contamination.

 

Ouroperations may be subject to the Clean Air Act (“CAA”) and comparable state andlocal requirements.  Amendments to theCAA were adopted in 1990 and contain provisions that have resulted in thegradual imposition of certain pollution control requirements with respect toair emissions from our operations.  TheEPA and states developed and continue to develop regulations to implement theserequirements.  We may be required toincur certain capital expenditures in the next several years for air pollutioncontrol equipment in connection with maintaining or obtaining operating permitsand approvals addressing other air emission-related issues.  However, we do not believe our operationswill be materially adversely affected by any such requirements.

 

Federalregulations require certain owners or operators of facilities that store orotherwise handle oil, such as Edge, to prepare and implement spill prevention,control, countermeasure (“SPCC”) and response plans relating to the possibledischarge of oil into surface waters. SPCC plans at our producing properties were developed and implemented in1999.  The Oil Pollution Act of 1990 (“OPA”)contains numerous requirements relating to the prevention of and response tooil spills into waters of the United States. The OPA subjects owners of facilities to strict joint and severalliability for all containment and cleanup costs and certain other damagesarising from a spill, including, but not limited to, the costs of responding toa release of oil to surface waters. Noncompliance with OPA may result in varying civil and criminalpenalties and liabilities.  Ouroperations are also subject to the federal Clean Water Act (“CWA”) andanalogous state laws.  In accordance withthe CWA, the state of Louisiana has issued regulations prohibiting dischargesof produced water in state coastal waters effective July 1, 1997.  Pursuant to other requirements of the CWA,the EPA has adopted regulations concerning discharges of storm waterrunoff.  This program requires coveredfacilities to obtain individual permits, participate in a group permit or seekcoverage under an EPA general permit. While certain of our properties may require permits for discharges ofstorm water runoff, we believe that we will be able to obtain, or be includedunder, such permits, where necessary, and make minor modifications to existingfacilities and operations that would not have a material effect on us.  Like OPA, the CWA and analogous state laws relatingto the control of water pollution provide varying civil and criminal penaltiesand liabilities for releases of petroleum or its derivatives into surfacewaters or into the ground.

 

CERCLA,also known as the “Superfund” law, and similar state laws impose liability,without regard to fault or the legality of the original conduct, on certainclasses of persons that are considered to have contributed to the release of a “hazardoussubstance” into the environment.  Thesepersons include the owner or operator of the disposal site or sites where therelease occurred and companies that disposed or arranged for the disposal ofthe hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substancesunder CERCLA may be subject to joint and several liability for the costs ofcleaning up the hazardous substances that have been released into theenvironment, for damages to natural resources and for the costs of certainhealth studies, and it is not uncommon for neighboring landowners and otherthird parties to file claims for personal injury and property damage allegedlycaused by the hazardous substances released into the environment.

 

Wealso are subject to a variety of federal, state and local permitting andregistration requirements relating to protection of the environment.  Management believes that we are insubstantial compliance with current applicable environmental laws andregulations and that continued compliance with existing requirements would nothave a material adverse effect on us.

 

# **OPERATINGHAZARDS AND INSURANCE**

# ** **

The oil and natural gas business involves a variety ofoperating risks, including the risk of fire, explosion, blow-out, pipe failure,casing collapse, abnormally pressured formations and environmental hazards suchas oil spills, natural gas leaks, ruptures and discharges of toxic gases, theoccurrence of any of which could result in

 

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substantial losses to usdue to injury or loss of life, severe damage to or destruction of property, naturalresources and equipment, pollution or other environmental damage, cleanupresponsibilities, regulatory investigation and penalties and suspension ofoperations.

 

Inaccordance with customary industry practice, we maintain insurance againstsome, but not all, of the risks described above.  Our insurance does not cover businessinterruption or protect against loss of revenue.  There can be no assurance that any insuranceobtained by us will be adequate to cover any losses or liabilities.  We cannot predict the continued availabilityof insurance or the availability of insurance at premium levels that justifyits purchase.  The occurrence of asignificant event not fully insured or indemnified against could materially andadversely affect our financial condition and operations.

 

**RISK FACTORS**

** **

**Oil andgas drilling is a speculative activity and involves numerous risks andsubstantial and uncertain costs****which could adversely affect us.**

 

Ourgrowth will be materially dependent upon the success of our future drillingprogram.  Drilling for oil and gasinvolves numerous risks, including the risk that no commercially productive oilor natural gas reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial anduncertain, and drilling operations may be curtailed, delayed or cancelled as aresult of a variety of factors beyond our control, including unexpecteddrilling conditions, pressure or irregularities in formations, equipmentfailures or accidents, adverse weather conditions, compliance with governmentalrequirements and shortages or delays in the availability of drilling rigs orcrews and the delivery of equipment.  Ourfuture drilling activities may not be successful and, if unsuccessful, suchfailure will have an adverse effect on our future results of operations andfinancial condition.  Our overalldrilling success rate or our drilling success rate for activity within aparticular geographic area may decline. We may ultimately not be able to leaseor drill identified or budgeted prospects within our expected time frame, or atall.  We may not be able to lease ordrill a particular prospect because, in some cases, we identify a prospect ordrilling location before seeking an option or lease rights in the prospect orlocation.  Similarly, our drilling schedule mayvary from our capital budget.  The finaldetermination with respect to the drilling of any scheduled or budgeted wellswill be dependent on a number of factors, including:

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

•                  the availability of sufficientcapital resources to us and the other participants for the drilling of theprospects;

•                  the approval of the prospects byother participants after additional data has been compiled;

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

•                  our financial resources and results;and

•                  the availability of leases andpermits on reasonable terms for the prospects.

 

These projects may not besuccessfully developed and the wells, if drilled, may not encounter reservoirsof commercially productive oil or natural gas. See *ITEM 7. “MANAGEMENT’S*DISCUSSION AND ANALYSIS OF FINANCIALCONDITION AND RESULTS OF OPERATIONS – INDUSTRY AND ECONOMIC FACTORS*”* and *ITEMS 1 AND 2. “BUSINESSAND PROPERTIES –*CORE AREASOF OPERATION.”

 

**Oil andnatural gas prices are highly volatile in general and low prices negativelyaffect our financial results.**

 

Ourrevenue, profitability, cash flow, future growth and ability to borrow funds orobtain additional capital, as well as the carrying value of our properties, aresubstantially dependent upon prevailing prices of oil and natural gas.  Our reserves are predominantly natural gas,therefore changes in natural gas prices may have a particularly large impact onour financial results.  Lower oil andnatural gas prices also may reduce the amount of oil and natural gas that wecan produce economically. Historically, the markets for oil and natural gashave been volatile, and such markets are likely to continue to be volatile inthe future.  Prices for oil and naturalgas are subject to wide fluctuation in response to relatively minor changes inthe supply of and demand for oil and natural gas, market uncertainty and avariety of additional factors that are beyond our control.  These factors include the level of consumerproduct demand, weather conditions, domestic and foreign governmental regulations,the price and availability of alternative fuels, political conditions, theforeign supply of oil and natural gas, the price of foreign

 

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imports and overalleconomic conditions.  Declines in oil andnatural gas prices may materially adversely affect our financial condition,liquidity, and ability to finance planned capital expenditures and results ofoperations.  See *ITEM 7. “MANAGEMENT’SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS –*DERIVATIVES AND HEDGING ACTIVITIES*” and ITEMS 1 AND 2. “BUSINESS AND PROPERTIES — OIL AND NATURAL GASRESERVES” and “– *MARKETING*.”*

 

Wehave in the past and may in the future be required to write down the carryingvalue of our oil and natural gas properties when oil and natural gas prices aredepressed or unusually volatile.  Whetherwe will be required to take such a charge will depend on the prices for oil andnatural gas at the end of any quarter and the effect of reserve additions or revisionsand capital expenditures during such quarter. If a write down is required, it would result in a charge to earnings andwould not impact cash flow from operating activities.

 

**Wehave hedged and may continue to hedge a portion of our production, which mayresult in our making cash payments or prevent us from receiving the fullbenefit of increases in prices for oil and gas.**

 

Inorder to reduce our exposure to short-term fluctuations in the price of oil andnatural gas, we periodically enter into hedging arrangements.  Our hedging arrangements apply to only aportion of our production and provide only partial price protection againstdeclines in oil and natural gas prices. Such hedging arrangements may expose us to risk of financial loss incertain circumstances, including instances where production is less thanexpected, our customers fail to purchase contracted quantities of oil ornatural gas or a sudden, unexpected event materially impacts oil or natural gasprices. In addition, our hedging arrangements may limit the benefit to us ofincreases in the price of oil and natural gas. See *ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS OF OPERATIONS –*DERIVATIVES AND HEDGING ACTIVITIES “ and*ITEMS 1 AND 2. “BUSINESS AND PROPERTIES –*MARKETING.”

 

**We dependon successful exploration, development and acquisitions to maintain reservesand revenue in the future.**

 

Ingeneral, the volume of production from oil and natural gas properties declinesas reserves are depleted, with the rate of decline depending on reservoircharacteristics.  Except to the extent weacquire properties containing proved reserves or conduct successful explorationand development activities, or both, our proved reserves will decline.  Our future oil and natural gas production is,therefore, highly dependent upon our level of success in finding or acquiringadditional reserves. In addition, we are dependent on finding partners for ourexploratory activity. To the extent that others in the industry do not have thefinancial resources or choose not to participate in our exploration activities,we could be adversely affected.

 

**We aresubject to substantial operating risks that may adversely affect the results ofour operations.**

 

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

 

We arenot the operator of some of our wells. As a result, our operating risks for those wells and our ability toinfluence the operations for these wells are less subject to our control.  Operators of these wells may act in ways thatare not in our best interests.  See*****ITEMS 1 AND 2. “BUSINESSAND PROPERTIES –*OPERATINGHAZARDS AND INSURANCE.”

 

**We cannotcontrol the activities on properties we do not operate and are unable to ensuretheir proper operation and profitability.**

 

We do not operate all of the properties in which wehave an interest.  As a result, we havelimited ability to exercise influence over, and control the risks associatedwith, operations of these properties. The failure of an operator of our wells to adequately performoperations, an operator’s breach of the applicable agreements or an operator’sfailure to act in ways that are in our best interest could reduce ourproduction and revenues.  The success andtiming of our drilling and development activities on properties operated byothers therefore depend upon a number of factors outside of our control,including the operator’s

 

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•                  timing and amount of capital expenditures;

•                  expertise and financial resources;

•                  inclusion of other participants in drilling wells; and

•                  use of technology.

 

**The lossof key personnel could adversely affect us.**

 

Wedepend to a large extent on the services of certain key management personnel,including our executive officers and other key employees, the loss of any ofwhich could have a material adverse effect on our operations.  We do not maintain key-man life insurancewith respect to any of our employees.  Webelieve that our success is also dependent upon our ability to continue toemploy and retain skilled technical personnel. See *ITEMS 1 AND 2. “BUSINESS AND PROPERTIES – TECHNOLOGY.”*

 

**Ouroperations have significant capital requirements which, if not met, will hinderoperations.**

 

Wehave experienced and expect to continue to experience substantial workingcapital needs due to our active exploration, development and acquisitionprograms.  Additional financing may berequired in the future to fund our growth. We may not be able to obtain such additional financing and financingunder existing or new credit facilities may not be available in the future.  In the event such capital resources are notavailable to us, our drilling and other activities may be curtailed.  See *ITEM 7. “MANAGEMENT’SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS –* LIQUIDITY AND CAPITAL RESOURCES*.”*

 

**Governmentregulation and liability for environmental matters may adversely affect ourbusiness and results of operations.**

 

Oiland natural gas operations are subject to various federal, state and localgovernment regulations, which may be changed from time to time.  Matters subject to regulation includedischarge permits for drilling operations, drilling bonds, reports concerningoperations, the spacing of wells, unitization and pooling of properties andtaxation.  From time to time, regulatoryagencies have imposed price controls and limitations on production by restrictingthe rate of flow of oil and natural gas wells below actual production capacityin order to conserve supplies of oil and natural gas.  There are federal, state and local laws andregulations primarily relating to protection of human health and the environmentapplicable to the development, production, handling, storage, transportationand disposal of oil and natural gas, by-products thereof and other substancesand materials produced or used in connection with oil and natural gasoperations.   In addition, we may beliable for environmental damages caused by previous owners of property wepurchase or lease.  As a result, we mayincur substantial liabilities to third parties or governmental entities.  We are also subject to changing and extensivetax laws, the effects of which cannot be predicted.  The implementation of new, or themodification of existing, laws or regulations could have a material adverseeffect on us.  See *ITEMS 1**AND 2.* “*BUSINESS ANDPROPERTIES –*INDUSTRYREGULATIONS.”

 

**We mayhave difficulty managing any future growth and the related demands on ourresources and may have difficulty in achieving future growth.**

 

Wehave experienced growth in the past through the expansion of our drillingprogram and, more recently, acquisitions. This expansion was curtailed in 1998and 1999, but resumed in 2000 and increased in subsequent years. Furtherexpansion is anticipated in 2005 both through increased drilling efforts andpossible acquisitions.  Any future growthmay place a significant strain on our financial, technical, operational andadministrative resources.  Our ability togrow will depend upon a number of factors, including our ability to identifyand acquire new exploratory prospects, our ability to develop existingprospects, our ability to continue to retain and attract skilled personnel, theresults of our drilling program and acquisition efforts, hydrocarbon prices andaccess to capital.   We may not besuccessful in achieving or managing growth and any such failure could have amaterial adverse effect on us.

 

**Weface strong competition from larger oil and natural gas companies.**

 

Theoil and gas industry is highly competitive. We encounter competition from oiland natural gas companies in all areas of our operations, including the acquisitionof exploratory prospects and productive oil and

 

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natural gas properties.Our competitors range in size from the major integrated oil and natural gascompanies to numerous independent oil and natural gas companies, individualsand drilling and income programs.  Manyof these competitors are large, well-established companies with substantiallylarger operating staffs and greater capital resources than us. We may not beable to successfully conduct our operations, evaluate and select suitableproperties,  consummate transactions, andobtain technical, managerial and other professional personnel in this highlycompetitive environment.  Specifically,these larger competitors may be able to pay more for exploratory prospects,productive oil and natural gas properties and competent personnel and may beable to define, evaluate, bid for and purchase a greater number of propertiesand prospects than our financial or human resources permit. In addition, such competitorsmay be able to expend greater resources on the existing and changingtechnologies that we believe are and will be increasingly important toattaining success in the industry. See*ITEMS 1 AND 2. “BUSINESS AND PROPERTIES –*COMPETITION.”

 

**The oiland natural gas reserve data included in or incorporated by reference in thisdocument are estimates based on assumptions that may be inaccurate and existingeconomic and operating conditions that may differ from future economic andoperating conditions.**

 

Reservoirengineering is a subjective and inexact process of estimating undergroundaccumulations of oil and natural gas that cannot be measured in an exact mannerand is based upon assumptions that may vary considerably from actual results.  Accordingly, reserve estimates may be subjectto downward or upward adjustment.  Actualproduction, revenue and expenditures with respect to our reserves will likelyvary from estimates, and such variances may be material. The informationregarding discounted future net cash flows included in this report should notbe considered as the current market value of the estimated oil and natural gasreserves attributable to our properties. As required by the SEC, the estimated discounted future net cash flowsfrom proved reserves are based on prices and costs as of the date of theestimate, while actual future prices and costs may be materially higher orlower.  Actual future net cash flows alsowill be affected by factors such as the amount and timing of actual production,supply and demand for oil and natural gas, increases or decreases inconsumption, and changes in governmental regulations or taxation.  In addition, the 10% discount factor, whichis required by Financial Accounting Standards Board in Statement of FinancialAccounting Standards No. 69, “*DisclosuresAbout Oil and Natural Gas Producing Activities*” to be used incalculating discounted future net cash flows for reporting purposes, is notnecessarily the most appropriate discount factor based on interest rates in effectfrom time to time and risks associated with us or the oil and natural gasindustry in general.  See *ITEMS 1 AND 2*. “*BUSINESS AND PROPERTIES –*OIL AND NATURAL GAS RESERVES.”

 

**Ourcredit facility has substantial operating restrictions and financial covenantsand we may have difficulty obtaining additional credit, which could adverselyaffect operations.**

 

Overthe past few years, increases in commodity prices, in proved reserve amountsand the resultant increase in estimated discounted future net revenue, hasallowed us to increase our available borrowing amounts.  In the future, commodity prices may decline,we may increase our borrowings or our borrowing base may be adjusteddownward.  Our credit facility is securedby a pledge of substantially all of our assets and has covenants that limitadditional borrowings, sales of assets and the distributions of cash orproperties and that prohibit the payment of dividends and the incurrence ofliens.  The revolving credit facilityalso requires that specified financial ratios be maintained.  The restrictions of our credit facility andthe difficulty in obtaining additional debt financing may have adverseconsequences on our operations and financial results, including our ability toobtain financing for working capital, capital expenditures, our drillingprogram, purchases of new technology or other purposes.  In addition, such financing may be on terms unfavorable to us and we may be requiredto use a substantial portion of our cash flow to make debt service payments,which will reduce the funds that would otherwise be available for operationsand future business opportunities. Further, a substantial decrease in ouroperating cash flow or an increase in our expenses could make it difficult forus to meet debt service requirements and require us to modify operations and wemay become more vulnerable to downturns in our business or the economygenerally.

 

Ourability to obtain and service indebtedness will depend on our futureperformance, including our ability to manage cash flow and working capital,which are in turn subject to a variety of factors beyond our control.  Our business may not generate cash flow at orabove anticipated levels or we may not be able to borrow funds in amountssufficient to enable us to service indebtedness, make anticipated capitalexpenditures or finance our drilling program. If we are unable to generate sufficient cash flow from operations or toborrow sufficient funds in the future to service our debt, we may be requiredto curtail portions of our drilling program, sell assets, reduce capital

 

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expenditures, refinanceall or a portion of our existing debt or obtain additional financing.  We may not be able to refinance our debt orobtain additional financing, particularly in view of current industryconditions, the restrictions on our ability to incur debt under our existingdebt arrangements, and the fact that substantially all of our assets arecurrently pledged to secure obligations under our bank credit facility.  See*ITEM7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OFOPERATIONS**–*LIQUIDITY AND CAPITAL RESOURCES”*and “**– CREDIT FACILITY.”*

 

**We maynot have enough insurance to cover all of the risks we face.**

 

In accordance with customary industry practices, wemaintain insurance coverage against some, but not all, potential losses inorder to protect against the risks we face. We do not carry business interruption insurance.  We may elect not to carry insurance if ourmanagement believes that the cast of available insurance is excessive relativeto the risks presented.  In addition, wecannot insure fully against pollution and environmental risks.  The occurrence of an event not fully coveredby insurance could have a material adverse effect on our financial conditionand results of operations.

 

**Ouracquisition program may be unsuccessful.**

 

Acquisitionshave become increasingly important to our business strategy in recent years.The successful acquisition of producing properties requires an assessment ofrecoverable reserves, future oil and natural gas prices, operating costs,potential environmental and other liabilities and other factors.  Such assessments, even when performed byexperienced personnel, are necessarily inexact and their accuracy inherentlyuncertain. Our review of subject properties will not reveal all existing orpotential problems, deficiencies and capabilities.  We may not always perform inspections onevery well, and may not be able to observe structural and environmentalproblems even when we undertake an inspection. Even when problems are identified, the seller may be unwilling or unableto provide effective contractual protection against all or part of suchproblems.  Any acquisition of propertyinterests by us may not be successful and, if unsuccessful, such failure mayhave an adverse effect on our future results of operations and financialcondition.

 

 

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**We do notintend to pay dividends and our ability to pay dividends is restricted.**

 

Wecurrently intend to retain any earnings for the future operation anddevelopment of our business and do not currently anticipate paying anydividends in the foreseeable future. We are currently restricted from payingdividends by our existing credit facility agreement. Any future dividends alsomay be restricted by our then-existing loan agreements.  See *ITEM 7. “MANAGEMENT’SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – LIQUIDITYAND CAPITAL RESOURCES*”and Note 10 to our consolidated financial statements.

 

**Ourreliance on third parties for gathering and distributing could curtail futureexploration and production activities.**

 

Themarketability of our production depends upon the proximity of our reserves to,and the capacity of, facilities and third party services, including oil andnatural gas gathering systems, pipelines, trucking or terminal facilities, andprocessing facilities.  Theunavailability or lack of capacity of such services and facilities could resultin the shut-in of producing wells or the delay or discontinuance of developmentplans for properties. A shut-in or delay or discontinuance could adverselyaffect our financial condition.  Inaddition, federal and state regulation of oil and natural gas production andtransportation affect our ability to produce and market our oil and natural gason a profitable basis.

 

**Provisionsof Delaware law and our charter and bylaws may delay or prevent transactionsthat would benefit stockholders.**

 

OurCertificate of Incorporation and Bylaws and the Delaware General CorporationLaw contain provisions that may have the effect of delaying, deferring orpreventing a change of control of the company. These provisions, among other things, provide for a classified Board ofDirectors with staggered terms, restrict the ability of stockholders to takeaction by written consent, authorize the Board of Directors to set the terms ofPreferred Stock, and restrict our ability to engage in transactions with 15%stockholders.

 

Becauseof these provisions, persons considering unsolicited tender offers or otherunilateral takeover proposals may be more likely to negotiate with our board ofdirectors rather than pursue non-negotiated takeover attempts.  As a result, these provisions may make itmore difficult for our stockholders to benefit from transactions that areopposed by an incumbent board of directors.

 

**Miller’sformer use of Arthur Andersen LLP as its independent public accountants may limityour ability to seek potential recoveries from them related to their work.**

 

ArthurAndersen LLP, independent public accountants, audited the consolidated balancesheet of Miller and its subsidiary as of December 31, 2001, and therelated consolidated statements of operations, equity and cash flows for theyear ending December 31, 2001. On June 15, 2002, Arthur Andersen wasconvicted on a federal obstruction of justice charge. On June 27, 2002,Miller dismissed Arthur Andersen and engaged Plante & Moran, PLLC.Arthur Andersen has ceased operations. As a result, any recovery any Edgestakeholder may have from Arthur Andersen related to the claims that suchstakeholder may assert related to the financial statements audited by ArthurAndersen, misstatements or omissions, if any, in this Form 10-K, will belimited by the financial circumstances of Arthur Andersen.

 

 

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**AVAILABLE INFORMATION**

 

Ourwebsite address is www.edgepet.com.  Wemake our website content available for information purposes only.  It should not be relied upon for investmentpurposes, nor is it incorporated by reference in this Form 10-K. We makeavailable on this website under “Investor Information-Financials/SEC Flings,”free of charge, our annual reports on Form 10-K, quarterly reports on Form10-Q, current reports on Form 8-K and amendments to those reports as soon asreasonably practicable after we electronically file those materials with, orfurnish those materials to, the SEC.  TheSEC also maintains a website at www.sec.gov that contains reports, proxystatements and other information regarding SEC registrants, including us.

 

**CERTAINDEFINITIONS**

 

Thedefinitions set forth below shall apply to the indicated terms as used in thisForm 10-K.  All volumes of natural gasreferred to herein are stated at the legal pressure base of the state or areawhere the reserves exist and at 60 degrees Fahrenheit and in most instances arerounded to the nearest major multiple.

 

*Afterpayout*.  With respectto an oil or natural gas interest in a property, refers to the time periodafter which the costs to drill and equip a well have been recovered.

 

*Bbl.*  One stock tank barrel, or 42 U.S. gallonsliquid volume, used herein in reference to crude oil or other liquidhydrocarbons.

 

*Bbls/d. *Stock tank barrels per day*.*

 

*Bcf*.  Billion cubic feet.

 

*Bcfe*.  Billion cubic feet equivalent, determinedusing the ratio of six Mcf of natural gas to one Bbl of crude oil, condensateor natural gas liquids.

 

*Beforepayout*.  With respectto an oil and natural gas interest in a property, refers to the time periodbefore which the costs to drill and equip a well have been recovered.

 

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

 

*Developedacreage*.  The number ofacres which are allocated or assignable to producing wells or wells capable ofproduction.

 

*Developmentwell*.  A well drilledwithin the proved area of an oil or natural gas reservoir to the depth of astratigraphic horizon known to be productive.

 

*Dry holeor well*.  A well foundto be incapable of producing hydrocarbons in sufficient quantities such thatproceeds from the sale of such production exceed the related oil and naturalgas operating expenses and taxes.

 

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

 

*Farm-inor farm-out.*  Anagreement whereunder the owner of a working interest in an oil and natural gaslease assigns the working interest or a portion thereof to another party whodesires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in orderto earn its interest in the acreage.  Theassignor usually retains a royalty and/or reversionary interest in thelease.  The interest received by anassignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

 

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

 

 

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*Findingcosts*.  Costsassociated with acquiring and developing proved oil and natural gas reserveswhich are capitalized by us pursuant to generally accepted accountingprinciples in the United States, including all costs involved in acquiringacreage, geological and geophysical work and the cost of drilling andcompleting wells, excluding those costs attributable to unproved property.

 

*Grossacres or gross wells.* The total acres or wells, as the case may be, in which a workinginterest is owned.

 

*MBbls*.  One thousand barrels of crude oil or otherliquid hydrocarbons.

 

*Mcf.*  One thousand cubic feet.

 

*Mcf/d*.  One thousand cubic feet per day.

 

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

 

*MMcf.*  One million cubic feet.

 

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

 

*Net acresor net wells*.  The sumof the fractional working interests owned in gross acres or gross wells.

 

*NGL’s*.  Natural gas liquids measured in barrels.

 

*NRI orNet Revenue Interests*. The share of production after satisfaction of all royalty, overridingroyalty, oil payments and other nonoperating interests.

 

*Normallypressured reservoirs.* Reservoirs with a formation-fluid pressure equivalent to 0.465 PSI perfoot of depth from the surface.  Forexample, if the formation pressure is 4,650 PSI at 10,000 feet, then thepressure is considered to be normal.

 

*Over-pressuredreservoirs*.  Reservoirssubject to abnormally high pressure as a result of certain types of subsurfaceformations.

 

*Petrophysicalstudy.*  Study of rockand fluid properties based on well log and core analysis.

 

*PlantProducts*.  Liquidsgenerated by a plant facility and include propane, iso-butane, normal butane,pentane and ethane.

 

*Presentvalue*.  When used withrespect to oil and natural gas reserves, the estimated future gross revenue tobe generated from the production of proved reserves, net of estimatedproduction and future development costs, using prices and costs in effect as ofthe date indicated, without giving effect to nonproperty-related expenses suchas general and administrative expenses, debt service and future income taxexpense or to depletion, depreciation, and amortization, discounted using anannual discount rate of 10%.

 

*Productivewell*.  A well that isfound to be capable of producing hydrocarbons in sufficient quantities such thatproceeds from the sale of such production exceeds production expenses andtaxes.

 

*Proveddeveloped nonproducing reserves*.  Proved developed reserves expected to berecovered from zones behind casing in existing wells.

 

 

24

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*Proveddeveloped producing reserves.* Proved developed reserves that are expected to be recovered fromcompletion intervals currently open in existing wells and able to produce tomarket.

 

*Proveddeveloped reserves.* Proved reserves that can be expected to be recovered from existing wellswith existing equipment and operating methods.

 

*Provedreserves*.  Theestimated quantities of crude oil, natural gas and natural gas liquids thatgeological and engineering data demonstrate with reasonable certainty to berecoverable in future years from known reservoirs under existing economic andoperating conditions.

 

*Provedundeveloped location.* A site on which a development well can be drilled consistent withspacing rules for purposes of recovering proved undeveloped reserves.

 

*Provedundeveloped reserves*. Proved reserves that are expected to be recovered from new wells onundrilled acreage or from existing wells where a relatively major expenditureis required for recompletion.

 

*Recompletion.* The completion forproduction of an existing well bore in another formation from that in which thewell has been previously completed.

 

*Reservoir.*  A porous and permeable underground formationcontaining a natural accumulation of producible oil and/or natural gas that isconfined by impermeable rock or water barriers and is individual and separatefrom other reservoirs.

 

*Royaltyinterest*.  An interestin an oil and natural gas property entitling the owner to a share of oil ornatural gas production free of costs of production.

 

*3-Dseismic*.  Advancedtechnology method of detecting accumulations of hydrocarbons identified througha three-dimensional picture of the subsurface created by the collection andmeasurement of the intensity and timing of sound waves transmitted into theearth as they reflect back to the surface.

 

*Undevelopedacreage*.  Lease acreageon which wells have not been drilled or completed to a point that would permitthe production of commercial quantities of oil and natural gas regardless of whethersuch acreage contains proved reserves.

 

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

 

*Workover.*  Operations on a producing well to restore orincrease production.

 

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***ITEM3.  LEGAL PROCEEDINGS***

 

From time to time we area party to various legal proceedings arising in the ordinary course ofbusiness.  While the outcome of lawsuitscannot be predicted with certainty, we are not currently a party to anyproceeding that we believe, if determined in a manner adverse to us, could havea potential material adverse effect on our financial condition, results ofoperations or cash flows.

 

During the second quarterof 2004, the Company received notice that its franchise tax returns for theState of Texas would be audited for the tax years 1999 through 2002. Afterreviewing documents submitted, the agent representing the Office of the Comptrollerof the State of Texas proposed adjustments to the calculation that would resultin an increased franchise tax liability. The agent maintained that transfers by the parent company to itssubsidiaries that the Company classified as intercompany loans should insteadbe classified as equity investments in the subsidiary. The State of Texasoriginally proposed that the franchise tax liability of the subsidiaries wouldbe increased by approximately $3.0 million for the four-year period underaudit.

 

During the third quarterof 2004 the agent reduced the proposed franchise tax deficiency adjustment tothe Company and its subsidiaries to an aggregate of $467,000. In the fourthquarter of 2004, there was an informal hearing at the local Comptroller’sOffice during which the agent indicated he would formally assess the proposeddeficiency.  The Company has not receivedany such deficiency assessment, but if it does, it intends to continue tovigorously contest the assessment through appropriate administrative levels inthe Comptroller’s Office and any other available means.  Due to its intention to continue tovigorously contest the proposed adjustments, the Company has not recognized anyprovision for the additional franchise taxes that would result from the proposeddeficiency.

 

***ITEM4.  SUBMISSION OF MATTERS TO A VOTE OFSECURITY HOLDERS***

 

NONE.

 

**ExecutiveOfficers of the Registrant**

 

Pursuantto Instruction 3 to Item 401(b)**of RegulationS-K and General Instruction G (3) to Form 10-K the following information isincluded in Part I of this Form 10-K.

 

**John W.Elias** has served as the Chief Executive Officer and Chairmanof the Board of the Company since November 1998.  From April 1993 to September 30,1998, he served in various senior management positions, including ExecutiveVice President, of Seagull Energy Corporation, a company engaged in oil andnatural gas exploration, development and production and pipelinemarketing.  Prior to April 1993, Mr.Elias served in various positions for more than 30 years, including seniormanagement positions with Amoco Corporation, a major integrated oil and gascompany.  Mr. Elias has more than 40years of experience in the oil and natural gas exploration and productionbusiness.  He is 64 years old.

 

# **MichaelG. Long**has served as Senior Vice President and ChiefFinancial Officer of the Company since December 1996 and as Treasurer ofthe Company since October 2004.  Mr.Long served as Vice President-Finance of W&T Offshore, Inc., an oil andnatural gas exploration and production company, from July 1995 to December 1996.  From May 1994 to July 1995, he served asVice President of the Southwest Petroleum Division for Chase Manhattan Bank,N.A.  Prior thereto, he served in variouscapacities with First National Bank of Chicago, most recently that of VicePresident and Senior Corporate Banker of the Energy and TransportationDepartment, from March 1992 to May 1994. Mr. Long received a B.A. in Political Science and a M.S. in Economicsfrom the University of Illinois.  Mr.Long is 52 years old.

# ** **

**John O.Tugwell** has served as Chief Operating Officer since March 2004and Senior Vice President Production since December 2001 and prior to thatserved as Vice President of Production for the Company since March 1997.He served as Senior Petroleum Engineer of the Company’s predecessor corporationsince May 1995.  From 1986 to May 1995,he held various reservoir/production engineering positions with Shell OilCompany, most recently that of Senior Reservoir Engineer.  Mr. Tugwell holds a B.S. in PetroleumEngineering from Louisiana State University. Mr. Tugwell is a registered Professional Engineer in the State ofTexas.  Mr. Tugwell is 41 years old.

 

26

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**SignificantEmployees**

 

**Mark J.Gabrisch** has served as the Vice President of Land for theCompany since March 1997.  From November 1994to March 1997, he served in a similar capacity with the Company’spredecessor corporation.  From 1985 to October 1994,he was a landman, most recently a Senior Landman, for Shell Oil Company.  Mr. Gabrisch holds a B.S. in Petroleum LandManagement from the University of Houston. Mr. Gabrisch is 44 years old.

 

**John O.Hastings, Jr.** has served as the Vice President of Explorationfor the Company since March 1997 and prior thereto served in a similarcapacity with the Company’s predecessor corporation since February 1994.  From 1984 to February 1994, he was anexploration geologist with Shell Oil Company, serving as Senior Geologistbefore his departure.  Mr. Hastings holdsa B.A. from Dartmouth in Earth Sciences and a M.S. in Geology from TexasA&M University. He is 45 years old.

 

**KirstenA. Hink**has served as Vice President & Controller of theCompany since October 1, 2003 and as Controller of the Company since December 31,2000.  Prior to that time she served asAssistant Controller from June 2000 to December 2000.  Before joining Edge, she served as Controllerof Benz Energy Inc., an oil and gas exploration company, from June 1998 toJune 2000.  Mrs. Hink received aB.S. in Accounting from Trinity University. Mrs. Hink is a Certified Public Accountant in the State of Texas.  She is 38 years old.

 

**James D. Keisling**has served as Vice President Production for the Company since April 2004.  From May 2000 to April 2004, he servedas Chief Engineer for the Company.  From August 1989to April 2000, he served as Production Manager of Ocean Energy, Inc.,serving as Southern Region Production Manager before his departure.  Mr. Keisling holds a B.S. degree in CivilEngineering from New Mexico State University. Mr. Keisling is a registered professional engineer in the state ofTexas.  He is 57 years old.

 

**C.W.MacLeod**has served asthe Senior Vice President Business Development and Planning for the Companysince April 2004 and Vice President Business Development and Planning forthe Company since January 2002. From November 1999 to December 2001,he was Vice President - Investment Banking with Raymond James and Associates,Inc.  From February 1990 to October 1999,Mr. MacLeod was a principal with Kirkpatrick Energy Associates, Inc., whoseprincipal business was merger and acquisition services, capital arrangement andanalytical services for the oil and gas producing industry.  Mr. MacLeod was responsible for originatingcorporate finance and research products for energy clients.  His previous experience includes positions asan independent petroleum geologist, a manager of exploration and production foran independent oil and gas producer and geologic positions with Ladd PetroleumCorporation and Resource Sciences Corporation. Mr. MacLeod graduated from Eastern Michigan University with a B.S. inGeology and earned his M.B.A. from the University of Tulsa.  Mr. MacLeod is a registered professionalgeologist in the state of Wyoming.  He is54 years old.

 

**Robert C.Thomas**has served as Vice President, General Counsel andCorporate Secretary since March 1997. From February 1991 to March 1997, he served in similarcapacities for the Company’s corporate predecessor.  From 1988 to January 1991, he wasassociate and acting general counsel for Mesa Limited Partnership in Amarillo,Texas.  Mr. Thomas holds a B.S. degree inFinance and a J.D. degree in Law from the University of Texas at Austin.  He is 51 years old.

 

27

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##### **PART II**

##### ** **

***ITEM5.  MARKET FOR REGISTRANT’S COMMONEQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES***

 

*MarketPrice of and Dividends on Common Equity and Related Stockholder Matters.*

 

As of March 11,2005, we estimate there were approximately 268 beneficial holders of our CommonStock.  Our Common Stock is listed on theNASDAQ National Market (“NASDAQ”) and traded under the symbol “EPEX”.  As of March 11, 2005, we had 17,100,155shares outstanding and our closing price on NASDAQ was $16.27 per share.  The following table sets forth, for theperiods indicated, the high and low closing sales prices for our Common Stockas listed on NASDAQ.

 
| ** **        | ** ** | **Common Stock Prices** | ** ** |
|-------------------|------------|-------------------------|------------|
| ** **        | ** ** | **High**                | ** ** | **Low** | ** ** |
| ** **        | ** ** | **($)**                 | ** ** | **($)** | ** ** |
| **Calendar 2004** |       |                    |       |   |   |
| First Quarter     |       | 14.61                   |       | 8.67 |   |
| Second Quarter    |       | 17.04                   |       | 12.50 |   |
| Third Quarter     |       | 19.24                   |       | 13.26 |   |
| Fourth Quarter    |       | 17.49                   |       | 13.43 |   |
|              |       |                    |       |   |   |
| **Calendar 2003** |       |                    |       |   |   |
| First Quarter     |       | 4.47                    |       | 3.72 |   |
| Second Quarter    |       | 6.15                    |       | 3.82 |   |
| Third Quarter     |       | 7.00                    |       | 4.85 |   |
| Fourth Quarter    |       | 11.20                   |       | 6.37 |   |

*** ***

***We have never paid a dividend, cash or otherwise, and do notintend to in the foreseeable future.  Inaddition, under our current credit facility, we are restricted from paying cashdividends on our Common Stock.  Thepayment of future dividends, if any, will be determined by our Board ofDirectors in light of conditions then existing, including our earnings,financial condition, capital requirements, restrictions in financingagreements, business conditions and other factors.  See***ITEMS 1 AND 2. “BUSINESS AND PROPERTIES – RISK FACTORS – We do not intend to pay dividendsand our ability to pay dividends is restricted.”

 

28

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***ITEM6.  SELECTED FINANCIAL DATA***

 

***The following table sets forth selected financial dataregarding the Company as of and for each of the periods indicated.  The following data should be read inconjunction with***ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS OF OPERATIONS” and our financial statements and notes theretoincluded in ITEM 8:

*** ***
| ** **                                                                            | ** ** | **Year Ended December 31,**              | ** ** |
|---------------------------------------------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                                                            | ** ** | **2004 (1)**                                  | ** ** | **2003(2)** | ** ** | **2002** | ** ** | **2001 (3)** | ** ** | **2000** | ** ** |
| ** **                                                                            | ** ** | **(in thousands, except per share  amounts)** | ** ** |
| **Statement of operations:**                                                          |       |                                          |       |   |   |   |   |   |   |   |   |
| Oil and natural gas revenue                                                           |       | $                                             | 64,505     |   | $ | 33,926 |   | $ | 20,911 |   | $ | 29,811 |   | $ | 23,774 |   |
| Operating expenses:                                                                   |       |                                          |       |   |   |   |   |   |   |   |   |
| Oil and natural gas operating expenses including  production and ad valorem taxes     |       | 9,309                                         |       | 5,116 |   | 3,831 |   | 5,001 |   | 3,955 |   |
| Depletion, depreciation, amortization and accretion  (2)                              |       | 21,928                                        |       | 13,577 |   | 10,427 |   | 9,378 |   | 7,641 |   |
| Litigation settlement                                                                 |       | —                                        |       | — |   | — |   | 3,547 |   | — |   |
| General and administrative expenses:                                                  |       |                                          |       |   |   |   |   |   |   |   |   |
| Deferred compensation expense ***–***  repriced options (4)                      |       | 1,136                                         |       | 1,219 |   | 4 |   | (850 | ) | 899 |   |
| Deferred compensation expense – restricted stock                                 |       | 498                                           |       | 372 |   | 399 |   | 353 |   | 128 |   |
| Other general and administrative                                                      |       | 7,813                                         |       | 5,541 |   | 4,826 |   | 5,038 |   | 3,824 |   |
| Total operating expenses                                                              |       | 40,684                                        |       | 25,825 |   | 19,487 |   | 22,467 |   | 16,447 |   |
|                                                                                  |       |                                          |       |   |   |   |   |   |   |   |   |
| Operating income                                                                      |       | 23,821                                        |       | 8,101 |   | 1,424 |   | 7,344 |   | 7,327 |   |
| Interest expense and amortization of deferred loan  costs, net of amounts capitalized |       | (473                                          | )          | (679 | ) | (228 | ) | (215 | ) | (172 | ) |
| Interest income                                                                       |       | 36                                            |       | 17 |   | 27 |   | 128 |   | 98 |   |
| Loss on sale of investment                                                            |       | —                                        |       | — |   | — |   | — |   | (355 | ) |
| Income before income taxes and cumulative effect of  accounting change                |       | 23,384                                        |       | 7,439 |   | 1,223 |   | 7,257 |   | 6,898 |   |
| Income tax (expense) benefit                                                          |       | (8,255                                        | )          | (2,731 | ) | (473 | ) | 819 |   | — |   |
| Income before cumulative effect of accounting change                                  |       | 15,129                                        |       | 4,708 |   | 750 |   | 8,076 |   | 6,898 |   |
| Cumulative effect of accounting change (2)                                            |       | —                                        |       | (358 | ) | — |   | — |   | — |   |
| Net income                                                                            |       | $                                             | 15,129     |   | $ | 4,350 |   | $ | 750 |   | $ | 8,076 |   | $ | 6,898 |   |
|                                                                                  |       |                                          |       |   |   |   |   |   |   |   |   |
| Basic earnings per share:                                                             |       |                                          |       |   |   |   |   |   |   |   |   |
| Income before cumulative effect of accounting change                                  |       | $                                             | 1.16       |   | $ | 0.48 |   | $ | 0.08 |   | $ | 0.87 |   | $ | 0.75 |   |
| Cumulative effect of accounting change                                                |       | —                                        |       | (0.03 | ) | — |   | — |   | — |   |
| Basic earnings per share                                                              |       | $                                             | 1.16       |   | $ | 0.45 |   | $ | 0.08 |   | $ | 0.87 |   | $ | 0.75 |   |
|                                                                                  |       |                                          |       |   |   |   |   |   |   |   |   |
| Diluted earnings per share:                                                           |       |                                          |       |   |   |   |   |   |   |   |   |
| Income before cumulative effect of accounting change                                  |       | $                                             | 1.11       |   | $ | 0.47 |   | $ | 0.08 |   | $ | 0.83 |   | $ | 0.74 |   |
| Cumulative effect of accounting change                                                |       | —                                        |       | (0.03 | ) | — |   | — |   | — |   |
| Diluted earnings per share                                                            |       | $                                             | 1.11       |   | $ | 0.44 |   | $ | 0.08 |   | $ | 0.83 |   | $ | 0.74 |   |
|                                                                                  |       |                                          |       |   |   |   |   |   |   |   |   |
| Basic weighted average number of shares outstanding  (5)                              |       | 13,029                                        |       | 9,726 |   | 9,384 |   | 9,281 |   | 9,183 |   |
| Diluted weighted average number of shares  outstanding (5)                            |       | 13,648                                        |       | 9,988 |   | 9,606 |   | 9,728 |   | 9,330 |   |
|                                                                                  |       |                                          |       |   |   |   |   |   |   |   |   |
| **EBITDA Reconciliation  (6):**                                                       | ** ** | ** **                                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net income                                                                            |       | $                                             | 15,129     |   | $ | 4,350 |   | $ | 750 |   | $ | 8,076 |   | $ | 6,898 |   |
| Cumulative  effect of accounting change (2)                                           |       | —                                        |       | 358 |   | — |   | — |   | — |   |
| Income tax  expense (benefit)                                                         |       | 8,255                                         |       | 2,731 |   | 473 |   | (819 | ) | — |   |
| Interest expense  and amortization of deferred loan costs, net of amounts capitalized |       | 473                                           |       | 679 |   | 228 |   | 215 |   | 172 |   |
| Interest income                                                                       |       | (36                                           | )          | (17 | ) | (27 | ) | (128 | ) | (98 | ) |
| Depletion,  depreciation, amortization and accretion (2)                              |       | 21,928                                        |       | 13,577 |   | 10,427 |   | 9,378 |   | 7,641 |   |
| **EBITDA**                                                                            |       | $                                             | 45,749     |   | $ | 21,678 |   | $ | 11,851 |   | $ | 16,722 |   | $ | 14,613 |   |
|                                                                                  |       |                                          |       |   |   |   |   |   |   |   |   |
| **Selected Cash Flow Data:**                                                          |       |                                          |       |   |   |   |   |   |   |   |   |
| Net cash provided by operating activities                                             |       | $                                             | 42,270     |   | $ | 23,898 |   | $ | 10,408 |   | $ | 22,151 |   | $ | 9,646 |   |
|                                                                                  |       |                                          |       |   |   |   |   |   |   |   |   |
| Capital expenditures                                                                  |       | $                                             | (89,470    | ) | $ | (33,560 | ) | $ | (19,610 | ) | $ | (28,989 | ) | $ | (10,718 | ) |
| Other investing activities                                                            |       | 60                                            |       | 5,490 |   | 355 |   | — |   | 5,323 |   |
| Net cash used in investing activities                                                 |       | $                                             | (89,410    | ) | $ | (28,070 | ) | $ | (19,255 | ) | $ | (28,989 | ) | $ | (5,395 | ) |
|                                                                                  |       |                                          |       |   |   |   |   |   |   |   |   |
| Net cash provided by (used in) financing activities                                   |       | $                                             | 48,080     |   | $ | 2,931 |   | $ | 10,623 |   | $ | 7,383 |   | $ | (4,003 | ) |
|                                                                                       |            |                                               |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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| ** **                                    | ** ** | **As of December 31,** | ** ** |
|-----------------------------------------------|------------|------------------------|------------|
| ** **                                    | ** ** | **2004 (1)**           | ** ** | **2003 (2)** | ** ** | **2002** | ** ** | **2001 (3)** | ** ** | **2000** | ** ** |
| ** **                                    | ** ** | **(in thousands)**     | ** ** |
| **Selected  Balance Sheet Data:**             |       |                   |       |   |   |   |   |   |   |   |   |
| ** **                                    |       |                   |       |   |   |   |   |   |   |   |   |
| Working capital                               |       | $                      | 8,957      |   | $ | 948 |   | $ | 3,310 |   | $ | 682 |   | $ | 2,879 |   |
| Property and  equipment, net                  |       | 165,840                |       | 97,981 |   | 75,682 |   | 66,853 |   | 47,242 |   |
|                                          |       |                   |       |   |   |   |   |   |   |   |   |
| Total assets                                  |       | 191,950                |       | 118,012 |   | 85,576 |   | 76,024 |   | 57,961 |   |
| Long-term debt,  including current maturities |       | 20,000                 |       | 21,000 |   | 20,500 |   | 10,000 |   | 3,000 |   |
| Stockholders’  equity (5)                |       | 150,467                |       | 82,011 |   | 58,533 |   | 58,099 |   | 50,129 |   |
|                                               |            |                        |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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(1)      Asdiscussed in Note 6 to our consolidated financial statements, we completed themerger with Miller in December 2003, this affects the comparability of ourresults in 2004 to other periods presented.

 

(2)      As discussed in Note 2 to our consolidatedfinancial statements, effective January 1, 2003, we changed our method ofaccounting for asset retirement obligations, this affects the comparability of ourresults in 2004 and 2003 to other periods presented.

 

(3)      Asdiscussed in Note 2 to our consolidated financial statements, effective January1, 2001, we changed our method of accounting for derivative instruments, thisaffects the comparability of our results in 2001 through 2004 to 2000.

 

(4)      Deferredcompensation expense includes the non-cash charge or credit related to FASBInterpretation No. (“FIN”) 44, “*Accountingfor Certain Transactions involving Stock Compensation.”*In May 1999,certain outstanding options were re-priced, which triggered the FIN 44requirement of variable accounting for modifications in the terms of thosestock options (see Note 2 to our consolidated financial statements).  Each period can be impacted by (i) re-pricedoptions that are exercised and (ii) the change in the value of outstandingrepriced options based on the price of our common stock at period-end.  Volatility in our stock price can have a significantimpact on this amount from period to period which may affect the comparabilityof our results for the periods presented.

 

(5)      Asdiscussed in Note 11 to our consolidated financial statements, we completed apublic offering of our common stock on December 21, 2004 and a significant propertyacquisition on December 29, 2004, therefore certain of our results in 2004 arenot directly comparable to other periods.

 

(6)                  EBITDAis defined as net income (loss) before cumulative effect of accounting change,interest expense and amortization of deferred loan costs (net of interestincome and amounts capitalized), income tax expense, depletion, depreciationand amortization and accretion expense. EBITDA is not defined under accountingprinciples generally accepted in the United States of America (“GAAP”). EBITDAis a financial measure commonly used in the oil and natural gas industry andshould not be considered in isolation or as a substitute for net income,operating income, cash flows from operating activities or any other measure offinancial performance presented in accordance with GAAP or as a measure of acompany’s profitability or liquidity. Because EBITDA excludes some, but notall, items that affect net income, this measure may vary among companies. TheEBITDA data presented above may not be comparable to a similarly titled measureof other companies. Our management believes that EBITDA is a meaningful measureto investors and may provide additional information about our ability to meetour future liquidity requirements.

 

We do not pay cash dividendsand have not in the periods presented above, therefore they are not presentedin the selected financial data.

 

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***ITEM7.  MANAGEMENT’S DISCUSSION AND ANALYSISOF FINANCIAL CONDITION AND RESULTS OF OPERATIONS***

 

The following is a reviewof our financial position and results of operations for the periodsindicated.  Our Consolidated FinancialStatements and Supplementary Information and the related notes thereto containdetailed information that should be referred to in conjunction with Management’sDiscussion and Analysis (“MD&A”) of Financial Condition and Results ofOperations.

 

**GENERAL OVERVIEW**

 

Edge Petroleum Corporation (“Edge” or the “Company”)is a Houston-based independent energy company that focuses its exploration,production and marketing activities in selected onshore basins of the UnitedStates. In late 1998, we undertook a top-level management change and began ashift in strategy from pure exploration, which focused more on prospect generation,to our current strategy which focuses on a balanced program of exploration,exploitation and development and acquisition of oil and gas properties. Ourcompany generates revenues, income and cash flows by producing and marketingoil and natural gas produced from our oil and natural gas properties. We makesignificant capital expenditures in our exploration, development, andacquisition activities that allow us to continue generating revenue, income andcash flows. In December 2003, we acquired 100 percent of the outstanding stockof Miller Exploration Company (“Miller”). The transaction was treated as a tax-free reorganization and accountedfor as a purchase business combination. Miller continues to conduct explorationand development activities as a wholly-owned subsidiary of Edge. In December2004, we acquired substantially all of the operating assets of Contango Oil& Gas Company (“Contango”) for a cash purchase price, financed by proceedsfrom a public offering of our common stock. This acquisition is hereinafterreferred to as the Contango Asset Acquisition.

 

This overview providesour perspective on the individual sections of MD&A, as well as helpfulhints for reading these pages. Our MD&A includes the following sections:

 

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

 

•                  **Approach to the Business** – additionalinformation regarding our approach and strategy.

 

•                  **Acquisitions and Divestitures** - informationabout significant changes in our business structure.

 

•                  **Outlook** – additional discussion relating tomanagement’s outlook to the future of our business.

 

•                  **Critical Accounting Policies and Estimates**– a discussion of certain accounting policies that require critical judgmentsand estimates.

 

•                  **Results of Operations** – an analysis of ourCompany’s consolidated results for the periods presented in our financialstatements.

 

•                  **Liquidity and Capital Resources -**ananalysis of cash flows, sources and uses of cash, and contractual obligations.

 

•                  **Risk Management Activities – Derivatives & Hedging–**supplementary information regarding our Company’s price-riskmanagement activities involving commodity contracts that are accounted for atfair value.

 

•                  **Tax Matters** – supplementary discussion ofincome tax matters.

 

•                  **Recently Issued Accounting Pronouncements** –a discussion of certain accounting pronouncements recently issued that mayimpact our future results.

 

31

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# **Industry and Economic Factors**

# ** **

In managing our business,we must deal with many factors inherent in our industry.  First and foremost is the fluctuation of oiland gas prices.  Historically, oil andgas markets have been cyclical and volatile, with future price movements, whichare difficult to predict.  While ourrevenues are a function of both production and prices, it is wide swings inprices that have most often had the greatest impact on our results ofoperations. We have no way to predict those prices or to control them withoutlosing some advantage of the upside potential.

 

Our operations entailsignificant complexities.  Advancedtechnologies requiring highly trained personnel are utilized in bothexploration and production.  Even whenthe technology is properly used, we may still not know conclusively ifhydrocarbons will be present or the rate at which they will be produced.  Exploration is a high-risk activity, oftentimes resulting in no commercially productive reserves being discovered.  Moreover, costs associated with operatingwithin our industry are substantial.

 

Our business, as withother extractive industries, is a depleting one in which each gas equivalentproduced must be replaced or we, and a critical source of our future liquidity,will shrink.

 

The oil and gas industryis highly competitive.  We compete withmajor and diversified energy companies, independent oil and gas businesses andindividual operators in exploration, production, marketing and acquisition activities.  In addition, the industry as a whole competeswith other businesses that supply energy to industrial and commercial endusers.

 

Extensive federal, stateand local regulation of the industry significantly affects our operations.  In particular, our activities are subject tostringent environmental regulations. These regulations have increased the costs of planning, designing,drilling, installing, operating and abandoning oil and gas wells and relatedfacilities.  These regulations may becomemore demanding in the future.

 

# **Approach to the Business**

# ** **

Profitable growth of ourbusiness will largely depend upon our ability to successfully find and developnew proved reserves of oil and natural gas in a cost-effective manner.  In order to achieve an overall acceptablerate of growth, we seek to maintain a prudent blend of low, moderate and higherrisk exploration and development projects. We also attempt to make selected acquisitions of oil and gas propertiesto augment our growth and provide future drilling opportunities.  To further mitigate risk, we have chosen toseek geologic and geographic diversification by operating in multiplebasins.  We periodically hedge ourexposure to volatile oil and gas prices on a portion of our production tomanage price risk. As of December 31, 2004, we have entered into hedgecontracts covering approximately 50% and 30% of our anticipated 2005 naturalgas and crude oil production, respectively, before any acquisitions.

 

Implementation of ourbusiness approach relies on our ability to fund ongoing exploration anddevelopment projects with cash flow provided by operating activities andexternal sources of capital.  In late2003, we announced plans for record capital expenditures of approximately $28million for 2004, which was subsequently expanded to $52 million. Our Boardrecently approved a 2005 capital budget of $63 million. Based on currentexpectations for production volumes and commodity prices, we expect to fundthose capital expenditures from internally generated cash from operatingactivities.  We do not typically includeacquisitions in our budgeted capital expenditures, but expect to fund thosewith either borrowings under our credit facility or offerings of common stock orother securities under our shelf registration statement or other sources.

 

In 2004, Edge reported a39% increase in proved reserves over the 2003 period, including the effect ofthe Contango Asset Acquisition (see Acquisitions and Divestitures below), and a49% increase in annual production volumes over the 2003 period.  We also replaced 308% of our total 2004production (see *ITEMS 1 AND 2. “BUSINESS AND PROPERTIES*-Oil and Natural Gas Reserve Replacement”). Production in the fourth quarter was15% higher than in the previous quarter and we exited 2004 with a record dailyproduction rate of 49.1 MMcfe/D as compared to 32.0 MMcfe/D a year ago. Webelieve that a strong financial position as represented by a debt to totalcapital ratio of 11.7%, available unused borrowing capacity and increased cashflow from our growing production volumes as a result of successful drilling andthe Contango Asset Acquisition completed in December 2004 will help lay theground work for our activities in

 

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2005.  Operationally and financially, we believe weare well positioned to continue the execution of our business strategy during2005.

 

**Acquisitions and Divestitures**

 

*Acquisitions*- We have become increasingly active in acquisitions inrecent years.  We have looked toacquisitions to enable us to achieve our desired growth and we expectacquisitions will continue to play a significant role in our future plans forgrowth.

 

On December 4, 2003, wecompleted our acquisition of Miller. Miller was an independent oil and gasexploration and production company with exploration efforts concentratedprimarily in the Mississippi Salt Basin of central Mississippi.  Under the terms of the merger agreement, eachshare of issued and outstanding common stock of Miller was converted into1.22342 shares of Edge common stock.  Weissued approximately 2.6 million shares of Edge common stock to theshareholders of Miller in exchange for all of the outstanding common stock ofMiller. The merger was treated as a tax-free reorganization and accounted foras a purchase business combination under generally accepted accountingprinciples. We operate the majority of the acquired properties. We acquiredMiller for the development and exploitation projects in Miller’s core area,increased financial flexibility, and expansion of our core areas. During 2004,we realized much of the exploitable potential of the Miller properties and willcontinue to focus on these opportunities in 2005.

 

On October 7, 2004, we executed an Asset PurchaseAgreement to acquire oil and natural gas properties located in south Texas fromContango for a cash purchase price of approximately $50 million. The purchaseprice was subject to adjustment for the results of operations between the July1, 2004 effective date and the December 29, 2004 closing date. The purchaseprice was preliminarily adjusted to $43.2 million at closing for the results ofoperations between the July 1, 2004 effective date and October 31, 2004.  In addition, at December 31, 2004 a furtherdownward adjustment of $3.4 million was accrued for the results of operationsfor November 1, 2004 through December 29, 2004, which we anticipate realizingin March 2005, pursuant to the post-closing adjustments provision. We financedthe acquisition with proceeds from a public offering of our common stock underour current shelf registration (see Note 11 to our consolidated financialstatements). The properties acquired consist of 39 non-operated producing wellswith working interests ranging from approximately 41% to 75% and net revenueinterests ranging from 29% to 56%. These properties, located primarily in JimHogg County, Texas and producing primarily from the Queen City formation, arein a geographic area that has been one of our most active and successful areasof focus in recent years. In addition to estimated proved reserves, ourtechnical team has also identified a substantial number of additional drillinglocations on undeveloped acreage with attractive exploitation and explorationpotential; therefore, we allocated $6 million of the purchase price to theunproved property category.

 

*Divestitures -*We regularlyreview our asset base for the purpose of identifying non-core assets, thedisposition of which would increase capital resources available for otheractivities and create organizational and operational efficiencies. While wegenerally do not dispose of assets solely for the purpose of reducing debt,such dispositions can have the result of furthering our objective of financialflexibility through reduced debt levels. During 2004, 2003 and 2002, ourdivestitures consisted of the sales of oil and gas properties for net proceedsof $60,000, $330,100 and $354,300, respectively. Our 2004 net proceeds fromasset divestitures were primarily derived from the sale of certain oil and gasproperties and equipment in Texas and Louisiana. Our 2003 net proceeds fromasset divestitures were primarily derived from the sale of our interest in twoaffiliated entities, Essex I and II Joint Ventures, and certain oil and gas propertiesin Texas and Louisiana. Our 2002 divestitures were primarily derived from thesale of certain interests in oil and gas properties in Texas, Alabama, Montana,and Louisiana.

 

**Outlook**

 

We completed asignificant asset acquisition and a public offering of common stock at the endof 2004. We expect to continue to spend considerable effort in 2005 onacquisitions, as we seek to further our growth. We expect our drilling programto increase from 49 wells (26.910 net) in 2004 to approximately 50 to 55 wells (28to 31 net) in 2005. Our expected capital program, excluding acquisitions, willbe approximately $63 million, approximately 21% greater than the approved 2004program. Our expected production volumes combined with a strongcommodity-pricing environment, that if sustained, is anticipated to produceanother year of record cash flow. In order to manage our realized growth in2004 and our anticipated growth for the next several years, we increased ourheadcount from

 

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35 employees as ofDecember 31, 2003 to 51 employees as of December 31, 2004 resulting inincreased G&A costs for 2004. We expect to add to our staff levels again in2005 both as a result of past growth and anticipated future growth. To helpprotect against the possibility of downward commodity price movements, we haveentered into several hedges covering approximately 50% of our expected naturalgas production and 30% of our expected crude oil production streams for 2005.

 

Our outlook and theexpected results described above are both subject to change based upon factorsthat include but are not limited to drilling results, commodity prices, accessto capital, the acquisitions market and factors referred to in “Forward LookingStatements.”

 

**CriticalAccounting Policies and Estimates**

 

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

 

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

 

•                  changes inthe estimate or different estimates that could have been selected could have amaterial impact on our consolidated results of operations or financialcondition.

 

All other significantaccounting policies that we employ are presented in the notes to theconsolidated financial statements. The following discussion presents informationabout the nature of our most critical accounting estimates, our assumptions orapproach used and the effects of hypothetical changes in the materialassumptions used to develop each estimate.

 

*Natureof Critical Estimate Item:*Oil & Natural Gas Reserves - Ourestimate of proved reserves is based on the quantities of oil and gas whichgeological and engineering data demonstrate, with reasonable certainty, to berecoverable in the future years from known reservoirs under existing economicand operating conditions.  The accuracyof any reserve estimate is a function of the quality of available data,engineering and geological interpretation, and judgment.  For example, we must estimate the amount andtiming of future operating costs, severance taxes, development costs, andworkover costs, all of which may in fact vary considerably from actualresults.  In addition, as prices and costlevels change from year to year, the economics of producing the reserves may changeand therefore the estimate of proved reserves also may change.  Any significant variance in these assumptionscould materially affect the estimated quantity and value of our reserves.Despite the inherent imprecision in these engineering estimates, our reservesare used throughout our financial statements.

 

*Assumptions/Approach Used:*Units-of-productionmethod to amortize our oil and natural gas properties - The quantity ofreserves could significantly impact our depletion expense. Any reduction inproved reserves without a corresponding reduction in capitalized costs willincrease the depletion rate.

 

* *“Ceiling” Test  - The full-cost method of accounting for oiland gas properties requires a quarterly calculation of a limitation oncapitalized costs, often referred to as a full-cost ceiling calculation. Theceiling is the discounted present value of our estimated total proved reservesadjusted for taxes and the impact of hedges on pricing, using a 10% discountrate. To the extent that our capitalized costs (net of accumulated depletionand deferred taxes) exceed the ceiling, the excess must be written off toexpense. Once incurred, this impairment of oil and gas properties is notreversible at a later date even if oil and gas prices increase. No suchimpairment was required in the years ended December 31, 2004, 2003, and 2002.This calculation of our proved reserves could significantly impact our ceilinglimitation used in determining whether an impairment of our capitalized costsis necessary. The ceiling calculation dictates that prices and costs in effectas of the last day of the period are generally held constant indefinitely.Therefore, the future net revenues associated with the estimated provedreserves are not based on our assessment of future prices or costs, but ratherare based on prices and costs in effect as of the end of the

 

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period. Oil and naturalgas prices used in the reserve valuation at December 31, 2004 were $43.46 perbarrel and $6.18 per MMbtu.

 

*Effectif different assumptions used:*Units-of-production method to amortizeour oil and natural gas properties - A 10% decrease in reserves would haveincreased our depletion expense for the year by 9%; however, a 10% increase inour reserves would have decreased our depletion expense for the year by 10%.

 

“Ceiling” limitationtest  - The most likelyfactor to contribute to a ceiling test impairment is the price used tocalculate the reserve limitation threshold. A significant reduction in theprices at a future measurement date could trigger a full-cost ceilingimpairment. At December 31, 2004, we had a cushion (i.e. the excess of theceiling over our capitalized costs) of $70.0 million. A 10% increase ordecrease in prices used would have increased or decreased our cushion by approximately50%. Our hedging program would serve to mitigate some of the impact of anyprice decline. Our hedges did not impact the ceiling test in the fourthquarter, and would not have if the price was 10% higher as these prices werewithin the collars, but had we decreased the price by 10% the price would havebeen less than our hedge floor and therefore resulted in a decrease in theceiling of $0.3 million. Another likely factor to contribute to a ceiling testimpairment is a revised estimate of reserve volume. A 10% increase or decreasein reserve volume would have increased or decreased our cushion by approximately35%.

 

*Natureof Critical Estimate Item:*Unproved Property Impairment****- We have elected to use the full-cost method to account forour oil and gas activities. Investments in unproved properties are notamortized until proved reserves associated with the properties can bedetermined or until impairment occurs. Unproved properties are evaluated quarterly for impairment on aproperty-by-property basis.  If theresults of an assessment indicate that an unproved property is impaired, theamount of impairment is added to the proved oil and natural gas property coststo be amortized.

 

*Assumptions/ApproachUsed:*At December 31, 2004, we had $15.5 million allocated tounproved property. This allocation is based on the estimation by the technicalteam of whether the property has potential attributable reserves. Therefore,the assessment made by our technical team of the potential reserves willdetermine whether costs are moved from the unproved category to the full-costpool for depletion or whether an impairment is taken.

 

*Effectif different assumptions used:* A 10% increase or decrease in theunproved property balance (i.e. transfer to full-cost pool) would haveincreased or decreased our depletion expense by 1% for the year ended December31, 2004.

 

*Natureof Critical Estimate Item:*Asset Retirement Obligations**-**We have certain obligations to removetangible equipment and restore land at the end of oil and gas productionoperations.  Our removal and restorationobligations are primarily associated with plugging and abandoning wells.Previously, the costs associated with this activity were capitalized to thefull-cost pool and charged to income through depletion. We adopted Statement ofFinancial Accounting Standards (“SFAS”) No. 143, “*Accounting for Asset Retirement Obligations*” effectiveJanuary 1, 2003, as discussed in Note 2 to our Consolidated FinancialStatements.  SFAS No. 143 significantlychanged the method of accruing for costs an entity is legally obligated toincur related to the retirement of fixed assets (“asset retirement obligations”or “ARO”).  Primarily, the new statementrequires us to estimate asset retirement costs for all of our assets, inflationadjust those costs to the forecast abandonment date, discount that amount usinga credit-adjusted-risk-free rate back to the date we acquired the asset orobligation to retire the asset and record an ARO liability in that amount witha corresponding addition to our asset value. We then accrete the liabilityquarterly using the period-end effective credit-adjusted-risk-free rate. As newwells are drilled or purchased, their initial asset retirement cost andliability is calculated and recorded. Should either the estimated life or theestimated abandonment costs of a property change upon our quarterly review, anew calculation is performed using the same methodology of taking theabandonment cost and inflating it forward to its abandonment date and thendiscounting it back to the present using our credit-adjusted-risk-free rate.The carrying value of the asset retirement obligation is adjusted to the newlycalculated value, with a corresponding offsetting adjustment to the assetretirement cost (included in the full-cost pool); therefore, abandonment costswill almost always

 

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approximate theestimate. When wells are sold the related liability and asset costs are removedfrom the Balance Sheet.

 

*Assumptions/Approach Used:*Estimating thefuture asset removal costs is difficult and requires management to makeestimates and judgments because most of the removal obligations are many yearsin the future and contracts and regulations often have vague descriptions ofwhat constitutes removal.  Asset removaltechnologies and costs are constantly changing, as are regulatory, political,environmental, safety and public relations considerations. Inherent in theestimate of the present value calculation of our AROs are numerous assumptionsand judgments including the ultimate settlement amounts, inflation factors,credit-adjusted-risk-free-rates, timing of settlement, and changes in thelegal, regulatory, environmental and political environments.

 

*Effectif different assumptions used:* Since there are so many variables inestimating AROs, we attempt to limit the impact of management’s judgment oncertain of these variables by using input of qualified third parties. We engagean independent engineering firm to evaluate our properties annually. We use theremaining estimated useful life from the year-end reserve reports by ourindependent reserve engineer in estimating when abandonment could be expectedfor each property. We utilize a three-year average rate for inflation todiminish any significant volatility that may be present in the short term. Weexpect to see our calculations impacted significantly if interest rates movefrom their current lows, as the credit-adjusted-risk-free rate is one of thevariables used on a quarterly basis. Our technical team developed a standardcost estimate based on historical costs, industry quotes and depth of wells.Unless we expect a well’s plugging to be significantly different than a normalabandonment, we use this estimate. The resulting estimate, after application ofa discount factor and some significant calculations, could differ from actualresults, despite all our efforts to make an accurate estimate.

 

*Natureof Critical Estimate Item:*Income Taxes**-**In accordance with the accounting for income taxes underSFAS No. 109, *Accounting for Income Taxes,*we have recorded a deferred tax asset and liability to account for the expectedfuture tax benefits and consequences of events that have been recognized in ourfinancial statements and our tax returns. There are several items that resultin deferred tax asset and liability impact to the balance sheet, but thelargest of which is income taxes and the impact of net operating loss (“NOL”)carryforwards. We routinely assess the realizability of our NOL carryforwardsthat resulted from substantial income tax deductions, prior year losses andacquisitions. We consider future taxable income in making suchassessments.  If we conclude that it ismore likely than not that some portion or all of the deferred tax assets willnot be realized under accounting standards, it is reduced by a valuationallowance.

 

*Assumptions/Approach Used:*Numerousjudgments and assumptions are inherent in the determination of future taxableincome, including factors such as future operating conditions (particularly asrelated to prevailing oil and gas prices). The Company is not currentlyrequired to pay any federal income taxes because of NOL carryforwards.

 

*Effect if different assumptions used:* Wehave engaged an independent public accounting firm to assist us in applying thenumerous and complicated tax law requirements. However, despite our attempt tomake an accurate estimate, the ultimate utilization of our NOL carryforwards ishighly dependent upon our actual production and the realization of taxableincome in future periods. If we estimate that some or all of our NOLcarryforwards are more likely than not going to expire or otherwise not beutilized to reduce future tax, we would record a valuation allowance to removethe benefit of those NOL carryforwards from our financial statements.

 

*Nature of Critical Estimate Item:*Derivative& Hedging Activities**-**Dueto the instability of oil and natural gas prices, we may enter into, from timeto time, price-risk management transactions (e.g., swaps, collars and floors)for a portion of our oil and natural gas production to achieve a morepredictable cash flow, as well as to reduce exposure from commodity pricefluctuations. While all of these transactions are economic hedges of pricerisk, different accounting treatment may apply depending on if they qualify forcash flow hedge accounting. In accordance with SFAS No. 133, *Accounting for Derivative Instruments and Hedging*

 

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*Activities(as amended),*all transactions are recorded on the balancesheet at fair value.  See*ITEMS 1 AND 2. “BUSINESS AND PROPERTIES**–*MARKETING.”

 

Hedge Contracts - We formally assess, both at thehedge’s inception and on an ongoing basis, whether the derivatives that areused for hedging are expected to be highly effective in offsetting changes incash flows of the hedged transactions. In the event it is determined that the use of a particular derivativemay not be or has ceased to be effective in pursuing a hedging strategy, hedgeaccounting is discontinued prospectively. The ongoing measurement ofeffectiveness determines whether the change in fair value is deferred throughother comprehensive income (“OCI”) on the balance sheet or recorded immediatelyin revenue on the income statement. The effective portion of the changes in thefair value of hedge contracts is recorded initially in OCI. When the hedgedproduction is sold, the realized gains and losses on the hedge contracts areremoved from OCI and recorded in revenue. Ineffective portions of the changesin the fair value of the hedge contracts are recognized in revenue as theyoccur. While the hedge contract is outstanding, the ineffective gain or lossmay increase or decrease until settlement of the contract.

 

Derivative Contracts -For transactions not accounted for using cash flow hedge accounting, the changein the fair value of the derivative contract is reflected in revenueimmediately, i.e. not deferred through OCI, and there is no measurement ofeffectiveness.

 

*Assumptions/ApproachUsed:*Estimating the fair values of derivative instrumentsrequires complex calculations, including the use of a discounted cash flowtechnique, estimates of risk and volatility, and subjective judgment inselecting an appropriate discount rate. In addition, the calculations usefuture market commodity prices, which although posted for trading purposes, aremerely the market consensus of forecasted price trends. The results of the fairvalue calculations cannot be expected to represent exactly the fair value ofour commodity hedges. We currently obtain the fair value of our positions fromour counterparties. Our practice of relying on our counterparties who are morespecialized and knowledgeable in preparing these complex calculations reducesour management’s input.

 

*Effect if different assumptions used:* AtDecember 31, 2004, a 10% change in the commodity price per unit, as long as theprice is either above the ceiling or below the floor price, would cause thefair value total of our derivative financial instrument to increase or decreaseby approximately $234,200.

 

# **RESULTS OF OPERATIONS**

# ** **

This section includes discussion of our 2004, 2003 and 2002 results ofoperations.  We are an independent energycompany engaged in the exploration, development, acquisition and production ofoil and natural gas.  Our resources andassets are managed and our results reported as one operating segment.  We conduct our operations primarily along theonshore United States, Gulf Coast, with our primary emphasis in south Texas,Louisiana and southeastern New Mexico.

 

**Year Ended December 31, 2004Compared to the Year Ended December 31, 2003**

 

**Revenue and Production**

 

Total revenue increased90% from 2003 to 2004.  For the yearsended December 31, 2004 and 2003, our product mix contributed the followingpercentages of production and revenues:

 
| ** **                  | ** ** | **REVENUES (1)** | ** ** | **PRODUCTION** | ** ** |
|-----------------------------|------------|------------------|------------|----------------|------------|
| ** **                  | ** ** | **2004**         | ** ** | **2003**       | ** ** | **2004** | ** ** | **2003** | ** ** |
| Natural gas  (Mcf)          |       | 82               | %          |           | 82         | % |   | 75 | % |   | 78 | % |   |
| Natural gas  liquids (Bbls) |       | 7                | %          |           | 7          | % |   | 14 | % |   | 13 | % |   |
| Crude oil (Bbl)             |       | 11               | %          |           | 11         | % |   | 11 | % |   | 9 | % |   |
|                        |       |             |       |           |       |   |   |   |   |   |   |   |   |
| Total (Mcfe)                |       | 100              | %          |           | 100        | % |   | 100 | % |   | 100 | % |   |

 

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(1) Includes effect ofhedging and derivative transactions.

 

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The following tablesummarizes production volumes, average sales prices and operating revenue forour oil and natural gas operations for the years ended December 31, 2004 and2003.

 
| ** **                                    | ** ** | ** **       | ** ** | ** **   | ** ** | **2004 Period Compared  to 2003 Period** | ** ** |
|-----------------------------------------------|------------|------------------|------------|--------------|------------|------------------------------------------|------------|
| ** **                                    | ** ** | ** **       | ** ** | **$**        | ** ** | **%**                                    | ** ** |
| ** **                                    | ** ** | **December 31,** | ** ** | **Increase** | ** ** | **Increase**                             | ** ** |
| ** **                                    | ** ** | **2004**         | ** ** | **2003 (1)** | ** ** | **(Decrease)**                           | ** ** | **(Decrease)** | ** ** |
| **Production  Volumes:**                      |       |             |       |         |       |                                     |       |   |   |
| Natural gas  (Mcf)                            |       | 9,148,191        |       | 6,290,055    |       | 2,858,136                                |       | 45 | % |
| Natural gas  liquids (Bbls)                   |       | 276,184          |       | 177,892      |       | 98,292                                   |       | 55 | % |
| Oil and  condensate (Bbls)                    |       | 214,622          |       | 122,592      |       | 92,030                                   |       | 75 | % |
| Natural gas  equivalent (Mcfe)                |       | 12,093,027       |       | 8,092,961    |       | 4,000,066                                |       | 49 | % |
| **Average  Sales Price:**                     |       |             |       |         |       |                                     |       |   |   |
| Natural gas ($ per  Mcf)(1)              |       | $                | 5.91       |         | $          | 5.14                                     |       | $ | 0.77 |   | 15 | % |
| Natural gas  liquids ($ per Bbl)         |       | $                | 15.83      |         | $          | 12.37                                    |       | $ | 3.46 |   | 28 | % |
| Oil and  condensate ($ per Bbl)(1)       |       | $                | 39.77      |         | $          | 31.48                                    |       | $ | 8.29 |   | 26 | % |
| Natural gas  equivalent ($ per Mcfe) (2) |       | $                | 5.33       |         | $          | 4.19                                     |       | $ | 1.14 |   | 27 | % |
| **Operating  Revenue:**                       |       |             |       |         |       |                                     |       |   |   |
| Natural gas (1)                               |       | $                | 54,056,944 |         | $          | 32,322,043                               |       | $ | 21,734,901 |   | 67 | % |
| Natural gas  liquids                          |       | 4,373,245        |       | 2,200,350    |       | 2,172,895                                |       | 99 | % |
| Oil and  condensate(1)                        |       | 8,535,222        |       | 3,859,204    |       | 4,676,018                                |       | 121 | % |
| Loss on hedging  and derivatives              |       | (2,460,063       | )          | (4,455,590   | )          | 1,995,527                                |       | 45 | % |
| Total (2)                                     |       | $                | 64,505,348 |         | $          | 33,926,007                               |       | $ | 30,579,341 |   | 90 | % |

 

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(1) Excludes theeffect of hedging and derivative transactions.

(2) Includes theeffect of hedging and derivative transactions.

** **

Ourrevenue is sensitive to changes in prices received for our products.  A substantial portion of our production issold at prevailing market prices, which fluctuate in response to many factorsthat are outside of our control. Imbalances in the supply and demand for oil and natural gas can have adramatic effect on the prices we receive for our production.  Political instability, availability ofalternative fuels, the economy, weather and other factors outside of ourcontrol could impact supply and demand. Several of these factors,including instability in the Middle East, lower inventories and a cold wintercontributed to commodity price increases in 2004.

 

Natural gasrevenue, excluding hedging activity, increased 67% for the year ended December31, 2004 over the same period in 2003 due to significantly higher productionand higher realized prices. Average natural gas production increased 45% from17.2 MMcf/D in 2003 to 25.0 MMcf/D in 2004 due to production from new wellsdrilled, primarily in our Gato Creek and Encinitas locations, and thoseacquired at the end of 2003, including the Miller and south Texas properties.Partially offsetting the increases in production were natural declines at our O’ConnorRanch and O’Connor Ranch East properties, as well as declines due to increasedsalt-water production on the Thibodeaux well. The overall increase inproduction compared to the prior year period resulted in an increase in revenueof approximately $14.7 million (based on 2003 comparable period pre-hedgeprices).  Excluding the effect of hedges,the average natural gas sales price for production in 2004 was $5.91 per Mcfcompared to $5.14 per Mcf for 2003.  Thisincrease in average price received resulted in increased revenue ofapproximately $7.0 million (based on current year production).

 

Revenue from thesale of NGLs increased 99% for the year ended December 31, 2004 over the sameperiod in 2003. Production volumes for NGLs increased 55%, from 487 Bbls/D for2003 to 755 Bbls/D for 2004 due primarily to increased production from newwells drilled at Gato Creek, Encinitas, Santellana, and Southeast New Mexico,those acquired at year-end 2003 from Miller and in south Texas, and newprocessing and treating agreements entered into during 2004. Our production atGato Creek receives a lower average price on NGL’s (approximately $1.20 perbarrel) due to the terms of our marketing agreement for that area. In 2003, themajority of our NGL production came from Gato Creek, whereas in 2004 we haveadded more market priced production that has increased our overall pricerealized. The increase in NGL production increased revenue by approximately$1.2 million (based on 2003 comparable period average prices).  Higher average realized prices for the yearended

 

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December 31, 2004resulted in an increase in revenue of approximately $1.0 million (based oncurrent year production).  The averagerealized price for NGLs for the year ended December 31, 2004 was $15.83 perbarrel compared to $12.37 per barrel for the same period in 2003.

 

Revenue from thesale of oil and condensate, excluding derivative activity, increased 121% forthe year ended December 31, 2004 as compared to the comparable prior yearperiod in 2003 due to increased production and realized prices. Productionvolumes for oil and condensate increased 75% to 586 Bbls/D for the year endedDecember 31, 2004 compared to 336 Bbls/D for the same prior year period dueprimarily to production from the properties acquired from Miller and in southTexas, as well as new wells drilled during 2004 at our Encinitas, Gato Creekand Southeast New Mexico properties. The increase in oil and condensateproduction resulted in an increase in revenue of approximately $2.9 million(based on 2003 comparable period average prices). The average realized pricefor oil and condensate before the derivative losses for the year ended December31, 2004 was $39.77 per barrel compared to $31.48 per barrel in the same periodof 2003.  These higher average prices for2004 resulted in an increase in revenue of approximately $1.8 million (based oncurrent year production).

 

Losses on hedgingand derivatives decreased 45% for the year ended December 31, 2004 over thesame period in 2003 due to better alignment of hedge and derivative contractswith market pricing. The volume and price contract terms vary from period toperiod and therefore interact differently with the market prices. While we areunable to predict the market prices, we enter into contracts that we expectwill protect us in the event of significant downturns in the market. Oil andcondensate revenues were decreased by realized and unrealized losses on our oilderivatives. For the year ended December 31, 2004 we recorded $880,765 ofrealized losses on oil derivatives settlements and $564,548 of unrealizedlosses representing the change in the mark-to-market fair value of ouroutstanding oil derivative contracts. We did not apply hedge accounting tothese transactions.  See Note 9 to ourconsolidated financial statements.  Theselosses account for a $6.74 per barrel decrease in the overall realized oilprice for the year ended December 31, 2004 from $39.77 per barrel to $33.03 perbarrel. There was no oil derivative activity during 2003. Should crude oilprices decrease from the current levels, we would realize lower revenues fromsales of crude oil, but our oil derivative losses would also decrease and couldpossibly result in a gain position. The actual pricing will also impact ourcash outlay as these transactions settle throughout the year. For the yearended December 31, 2004, we recognized the $686,250 premium paid for a naturalgas hedge entered into in 2003 and $328,500 representing realized losses fromnatural gas hedging contract settlements. These losses decreased the effective natural gas sales price by $0.11per Mcf.  Included within revenue for theyear ended December 31, 2003 was $4.5 million representing realized losses fromnatural gas hedging contract settlements. These losses decreased the effective natural gas sales price by $0.71per Mcf for 2003.  Should natural gasprices decrease from the current high levels, this could materially affect ourrevenues that are not hedged.

 

**Costs andOperating Expenses**

 

The table below presentsa detail of our 2004 and 2003 expenses:

 
| ** **                                            | ** ** | ** **       | ** ** | ** **   | ** ** | **2004 Period Compared  to 2003 Period** | ** ** |
|-------------------------------------------------------|------------|------------------|------------|--------------|------------|------------------------------------------|------------|
| ** **                                            | ** ** | ** **       | ** ** | **$**        | ** ** | **%**                                    | ** ** |
| ** **                                            | ** ** | **December 31,** | ** ** | **Increase** | ** ** | **Increase**                             | ** ** |
| ** **                                            | ** ** | **2004**         | ** ** | **2003**     | ** ** | **(Decrease)**                           | ** ** | **(Decrease)** | ** ** |
|                                                  |       |             |       |         |       |                                     |       |   |   |
| Lease operating  expenses                             |       | $                | 4,945,918  |         | $          | 2,676,050                                |       | $ | 2,269,868 |   | 85 | % |
| Severance and ad  valorem taxes                       |       | 4,362,852        |       | 2,439,744    |       | 1,923,108                                |       | 79 | % |
| Depreciation,  depletion, amortization and accretion: |       |             |       |         |       |                                     |       |   |   |
| Oil and gas property  and equipment                   |       | 21,471,606       |       | 12,906,956   |       | 8,564,650                                |       | 66 | % |
| Other assets                                          |       | 357,300          |       | 603,698      |       | (246,398                                 | )          | (41 | )% |
| ARO accretion                                         |       | 98,968           |       | 66,625       |       | 32,343                                   |       | 49 | % |
| General and  administrative:                          |       |             |       |         |       |                                     |       |   |   |
| Deferred  compensation – repriced options        |       | 1,135,628        |       | 1,219,349    |       | (83,721                                  | )          | (7 | )% |
| Deferred  compensation – restricted stock        |       | 498,372          |       | 372,151      |       | 126,221                                  |       | 34 | % |
| Other general  and administrative                     |       | 7,812,970        |       | 5,540,140    |       | 2,272,830                                |       | 41 | % |
|                                                  |       | 40,683,614       |       | 25,824,713   |       | 14,858,901                               |       | 58 | % |
| Other expense,  net                                   |       | 437,459          |       | 662,287      |       | (224,828                                 | )          | (34 | )% |
| Total                                                 |       | $                | 41,121,073 |         | $          | 26,487,000                               |       | $ | 14,634,073 |   | 55 | % |
|                                                       |            |                  |            |              |            |                                          |            |  |  |  |  |  |  |  |

 

39

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Lease operating expenses for the year ended December31, 2004 totaled $4.9 million compared to $2.7 million in the same period of2003, an increase of 85%.  Current yearresults were impacted by the addition of the Miller and south Texas properties(acquisitions late in 2003) and the drilling of 40 successful wells during2004.  Operating expenses averaged $0.41per Mcfe for the year ended December 31, 2004 compared to $0.33 per Mcfe forthe prior year period.

 

Severance and ad valoremtaxes for the year ended December 31, 2004 increased 79% over 2003.  Severance tax expense for 2003 was 97% higherthan the prior year period as a result of higher revenue. Severance taxes arelevied directly off of our revenue dollar, so the increase is consistent withthe 90% increase in revenue. The rate realized for the year also increased as aresult of the changing mix of our production locations. We had a significantportion of production in other states such as Louisiana in 2003 as compared tothe increase in production in Texas in 2004, which imposes a tax rate ofapproximately 7.5% of the revenue dollar. For the year ended December 31, 2004,severance tax expense was approximately 6.0% of total revenue compared to 5.3%of total revenue for the comparable 2003 period.  Ad valorem costs decreased 5% since 2003 as aresult of adjustments to expense estimates accrued in 2003. On an equivalentbasis, severance and ad valorem taxes averaged $0.36 per Mcfe and $0.30 perMcfe for the years ended December 31, 2004 and 2003, respectively.

 

DD&A and accretionexpense for the year ended December 31, 2004 increased 62% over the year endedDecember 31, 2003.  Full cost depletionon our oil and natural gas properties totaled $21.5 million for 2004 comparedto $12.9 million in 2003 due to both increases in production and the depletionrate. For the year ended December 31, 2004, higher oil and natural gasproduction compared to the prior year period resulted in an increase indepletion expense of $6.4 million. Depletion expense on a unit of production basis for the year endedDecember 31, 2004 was $1.78 per Mcfe, 12% higher than the 2003 rate of $1.59per Mcfe. The higher depletion rate per Mcfe resulted in an increase indepletion expense of $2.2 million.  Theincrease in the depletion rate was primarily due to a higher amortizable basein 2004 compared to the prior year without a corresponding increase inreserves.  Depreciation of other assetsdecreased 41% since 2003 due to accelerating depreciation on leaseholdimprovements and computer equipment in 2003. When we moved to a new officebuilding early in 2003, we fully depreciated certain assets that would nolonger be in service in the new location. Many older assets became fullydepreciated at that time and were not replaced in 2004. Accretion expense on our ARO liabilityhas increased 49% for the addition of new obligations associated with wellsadded during 2004, as well as the fact that accretion is calculated using theinterest method of allocation, which calculates interest on the cumulativebalance such that the interest increases with each subsequent period.

 

Total general and administrative(“G&A”) expenses for the year ended December 31, 2004 were $9.4 million, anincrease of 32% compared to the prior year total of $7.1 million.  Total G&A costs include deferredcompensation related to repriced options, deferred compensation related torestricted stock grants and other G&A costs.

 

Deferred compensationexpense consists of costs reported in accordance with FIN 44**and amortizationrelated to restricted stock awards. FIN 44 requires variable accounting forstock options with terms modified after issuance (see Note 2 to ourconsolidated financial statements). Variable accounting provides for anon-cash charge to compensation expense if the price of our common stock on thelast trading day of a reporting period is greater than the exercise price ofcertain re-priced options.  FIN 44 couldalso result in a credit to compensation expense to the extent that the tradingprice declines from the trading price as of the end of the prior period, butnot below the exercise price of the options. We adjust deferred compensationexpense upward or downward on a monthly basis based on the trading price at theend of each such period. We are required to report under this rule as a resultof non-qualified stock options granted to employees and directors in prioryears and re-priced in May of 1999, as well as certain newly issued options inconjunction with the re-pricing.  A FIN 44 charge on our re-priced stockoptions was required in both 2004 and 2003 as a result of our stock priceexceeding the exercise price of those re-priced options. The increase indeferred compensation for restricted stock awards is related to the increase inemployee headcount during 2004.

 

40

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Other G&A expensesfor the year ended December 31, 2004, which does not include the deferredcompensation expenses discussed above increased 41% since 2003.  The increase in other G&A was in partattributable to the growth in our company from 35 employees at December 31,2003 to 51 employees at December 31, 2004. We were also impacted by higheraudit and legal fees and amounts spent on investor relations projects during2004. We incurred approximately $390,400 of costs for the implementation of theSarbanes-Oxley 404 Internal Control Report during 2004. This does not includeany amounts of the significant internal resources that were directed towardsthis project. These increases were partially offset by decreases in generaloffice related spending in 2004. Included in 2003 was a $70,000 settlement fora lawsuit related to seismic rights. For the years ended December 31, 2004 and2003, overhead reimbursement fees reduced G&A costs by approximately$262,000 and $120,500, respectively. The Company capitalized $2.2 million and$1.7 million of general and administrative costs in 2004 and 2003,respectively.  Other G&A expenses ona unit of production basis for the year ended December 31, 2004 was $0.65 perMcfe compared to $0.68 per Mcfe for the comparable 2003 period.

 

Included in otherincome (expense) was interest expense, net of amounts capitalized, of $331,399for the year ended December 31, 2004 compared to $678,805 in the same 2003period.  Interest expense, includingfacility fees, was $1.0 million for 2004 on weighted average debt of $20.0million compared to interest expense of $923,308 on weighted average debt ofapproximately $23.0 million for 2003. Capitalized interest for the year endedDecember 31, 2004 totaled $701,654 compared to $244,503 in the prior year. AtDecember 31, 2004, our unproved property balance was $15.5 million compared to$5.0 million at December 31, 2003, resulting in the lower capitalized interestfor 2003.  Also included in other income(expense) for the year ended December 31, 2004 was $142,135 representingamortization of deferred loan costs associated with our credit facility.

 

Interest income totaled$36,075 for the year ended December 31, 2004 compared to $16,518 for the sameperiod in 2003.  The increase in interestincome is due primarily to the overall increase in funds that were invested inovernight money market funds, especially in December in the period betweenreceipt of offering proceeds and closing the Contango Asset Acquisition.

 

An income tax provision was recorded for the yearended December 31, 2004 of $8.3 million. For the year ended December 31, 2003, an income tax provision of $2.7million was recorded. Due to changes in amounts of permanent tax differences,including meals and entertainment and compensation expense, our effective taxrate changed from 36.7% in 2003 to 35.3% in 2004.  As of December 31, 2004, approximately $73.9million of net operating loss carryforwards have been accumulated or acquiredthat will begin to expire in 2007. Currently, we do not anticipate making federal tax payments in 2005.

 

Upon adoption of SFASNo. 143 on January 1, 2003, we recorded a cumulative effect of a change inaccounting principal of $357,825 (net of income taxes of $192,675) andaccretion expense, to recognize transition amounts for asset retirementobligations, asset retirement costs and accumulated depletion and accretion.

 

For the year endedDecember 31, 2004, we had net income of $15.1 million, or $1.16 basic earningsper share and $1.11 diluted earnings per share, as compared to net income of$4.4 million, or $0.45 basic and $0.44 diluted earnings per share in 2003.  Basic weighted average shares outstandingincreased from approximately 9.7 million for the year ended December 31, 2003to 13.0 million in the comparable 2004 period. The impact of the shares issuedin the Miller transaction was not fully realized until 2004 since the mergerclosed and the shares were issued in December 2003. The same is true in 2004for the shares issued in the public offering in December 2004. There were alsoincreases due to options exercised and vesting of restricted stock during 2004.

 

**Year Ended December 31, 2003Compared to the Year Ended December 31, 2002**

 

**Revenue and Production**

 

Total revenue increased62% from 2002 to 2003.  For the yearsended December 31, 2003 and 2002, our product mix contributed the followingpercentages of production and revenues:

 
| ** **                  | ** ** | **REVENUES (1)** | ** ** | **PRODUCTION** | ** ** |
|-----------------------------|------------|------------------|------------|----------------|------------|
| ** **                  | ** ** | **2003**         | ** ** | **2002**       | ** ** | **2003** | ** ** | **2002** | ** ** |
| Natural Gas  (Mcf)          |       | 82               | %          |           | 79         | % |   | 78 | % |   | 76 | % |   |
| Natural gas  liquids (Bbls) |       | 7                | %          |           | 8          | % |   | 13 | % |   | 14 | % |   |
| Crude oil (Bbl)             |       | 11               | %          |           | 13         | % |   | 9 | % |   | 10 | % |   |
|                        |       |             |       |           |       |   |   |   |   |   |   |   |   |
| Total (Mcfe)                |       | 100              | %          |           | 100        | % |   | 100 | % |   | 100 | % |   |

 

41

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----

(1) Includes effect of hedging and derivativetransactions.

 

The following tablesummarizes production volumes, average sales prices and operating revenue forour oil and natural gas operations for the years ended December 31, 2003 and2002.

 

 
| ** **                                    | ** ** | ** **       | ** ** | ** **   | ** ** | **2003 Period Compared  to 2002 Period** | ** ** |
|-----------------------------------------------|------------|------------------|------------|--------------|------------|------------------------------------------|------------|
| ** **                                    | ** ** | ** **       | ** ** | **$**        | ** ** | **%**                                    | ** ** |
| ** **                                    | ** ** | **December 31,** | ** ** | **Increase** | ** ** | **Increase**                             | ** ** |
| ** **                                    | ** ** | **2003**         | ** ** | **2002(1)**  | ** ** | **(Decrease)**                           | ** ** | **(Decrease)** | ** ** |
| **Production  Volumes:**                      |       |             |       |         |       |                                     |       |   |   |
| Natural gas  (Mcf)                            |       | 6,290,055        |       | 5,266,390    |       | 1,023,665                                |       | 19 | % |
| Natural gas  liquids (Bbls)                   |       | 177,892          |       | 161,301      |       | 16,591                                   |       | 10 | % |
| Oil and  condensate (Bbls)                    |       | 122,592          |       | 119,527      |       | 3,065                                    |       | 3 | % |
| Natural gas  equivalent (Mcfe)                |       | 8,092,961        |       | 6,951,357    |       | 1,141,604                                |       | 16 | % |
| **Average  Sales Price:**                     |       |             |       |         |       |                                     |       |   |   |
| Natural gas ($ per  Mcf)(3)              |       | $                | 5.14       |         | $          | 3.20                                     |       | $ | 1.94 |   | 61 | % |
| Natural gas  liquids ($ per Bbl)         |       | $                | 12.37      |         | $          | 10.31                                    |       | $ | 2.06 |   | 20 | % |
| Oil and  condensate ($ per Bbl)(3)       |       | $                | 31.48      |         | $          | 22.88                                    |       | $ | 8.60 |   | 38 | % |
| Natural gas  equivalent ($ per Mcfe) (2) |       | $                | 4.19       |         | $          | 3.01                                     |       | $ | 1.18 |   | 39 | % |
| **Operating  Revenue:**                       |       |             |       |         |       |                                     |       |   |   |
| Natural gas (3)                               |       | $                | 32,322,043 |         | $          | 16,840,046                               |       | $ | 15,481,997 |   | 92 | % |
| Natural gas  liquids                          |       | 2,200,350        |       | 1,663,707    |       | 536,643                                  |       | 32 | % |
| Oil and  condensate(3)                        |       | 3,859,204        |       | 2,734,491    |       | 1,124,713                                |       | 41 | % |
| Loss on hedging  and derivatives              |       | (4,455,590       | )          | (326,950     | )          | (4,128,640                               | )          | 1263 | % |
| Total                                         |       | $                | 33,926,007 |         | $          | 20,911,294                               |       | $ | 13,014,713 |   | 62 | % |
|                                               |            |                  |            |              |            |                                          |            |  |  |  |  |  |  |  |  |

 

----

(1)          Results for 2002 werefavorably impacted by the recognition in the second quarter of 2002 of revenueassociated with underaccruals in prior periods. This adjustment resulted in 142MMcfe of additional production and $577,200 of additional revenue.

(2)          Includes the effect ofhedging and derivative transactions.

(3)          Excludes the effect ofhedging and derivative transactions.

 

Natural gas revenue, excluding hedging activity,increased 92% from $16.8 million for the year ended December 31, 2002 to $32.3million for 2003 due to significantly higher average realized prices coupledwith an increase in production, partially offset by a higher realized hedgeloss.  Excluding the effect of hedges,the average natural gas sales price for production in 2003 was $5.14 per Mcfcompared to $3.20 per Mcf for 2002.  Thisincrease in average price received resulted in increased revenue ofapproximately $12.2 million (based on 2003 production).  For the year ended December 31, 2003, averagenatural gas production increased 19% from 14.4 MMcf/d in 2002 to 17.2 MMcf/d in2003 due to production from new wells drilled and acquired, primarily ourO’Connor Ranch East, Gato Creek and Encinitas properties, partially offset bynatural declines at our Austin Field and O’Connor Ranch properties.  This increase in production compared to theprior year resulted in an increase in revenue of approximately $3.3 million(based on 2002 comparable period prices).

 

Revenue from the sale of oil and condensate totaled$3.9 million for the year ended December 31, 2003, an increase of 41% from theprior year total of $2.7 million.  Theaverage realized price for oil and condensate for the year ended December 31,2003 was $31.48 per barrel compared to $22.88 per barrel in 2002.  Higher average prices for the year 2003resulted in an increase in revenue of approximately $1.1 million (based on 2003production).  Production volumes for oiland condensate increased 3% to 336 Bbls/d for the year ended December 31, 2003compared to 327 Bbls/d for the same prior year period.  The increase in oil and condensate productionresulted in an increase in revenue of approximately $70,100 (based on 2002comparable period average prices).

 

Revenue from the sale of NGLs totaled $2.2 million forthe year ended December 31, 2003, an increase of 32% from the 2002 total of$1.7 million. Higher average realized prices for the year ended December 31,2003

 

42

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resulted in an increase in revenue of $365,500 (based on 2003production).  The average realized pricefor NGLs for the year ended December 31, 2003 was $12.37 per barrel compared to$10.31 per barrel for the same period in 2002. Production volumes for NGLs increased 10%, from 442 Bbls/d for the yearended December 31, 2002 to 487 Bbls/d for the year ended December 31, 2003 dueprimarily to new production from the Thibodeaux well.  The increase in NGL production increasedrevenue by $171,100 (based on 2002 comparable period average prices).

 

Losses on hedging andderivatives increased significantly for the year ended December 31, 2003 overthe same period in 2002 due to the unexpected movement of prices in the market.Included within natural gas revenue for the year ended December 31, 2003 and2002 was $4.5 million and $0.3 million, respectively, representing cashsettlement losses from natural gas hedging activity.  Including the effect of our hedges, ouraverage natural gas sales price for production in 2003 was $4.43 per Mcfcompared to $3.14 per Mcf for 2002. These losses decreased the effectivenatural gas sales price by $0.71 per Mcf and $0.06 per Mcf, for the years endedDecember 31, 2003 and 2002, respectively.

 

**Costs andOperating Expenses**

** **

The table belowpresents a detail of our 2003 and 2002 expenses:

 
| ** **                                     | ** ** | ** **       | ** ** | ** **   | ** ** | **2003 Period Compared  to 2002 Period** | ** ** |
|------------------------------------------------|------------|------------------|------------|--------------|------------|------------------------------------------|------------|
| ** **                                     | ** ** | ** **       | ** ** | **$**        | ** ** | **%**                                    | ** ** |
| ** **                                     | ** ** | **December 31,** | ** ** | **Increase** | ** ** | **Increase**                             | ** ** |
| ** **                                     | ** ** | **2003**         | ** ** | **2002**     | ** ** | **(Decrease)**                           | ** ** | **(Decrease)** | ** ** |
|                                           |       |             |       |         |       |                                     |       |   |   |
| Lease operating  costs                         |       | $                | 2,676,050  |         | $          | 2,208,892                                |       | $ | 467,158 |   | 21 | % |
| Severance and ad  valorem taxes                |       | 2,439,744        |       | 1,622,698    |       | 817,046                                  |       | 50 | % |
| Depreciation,  depletion, and amortization:    |       |             |       |         |       |                                     |       |   |   |
| Oil and gas  property and equipment            |       | 12,906,956       |       | 9,697,144    |       | 3,209,812                                |       | 33 | % |
| Other assets                                   |       | 603,698          |       | 729,523      |       | (125,825                                 | )          | (17 | )% |
| ARO accretion                                  |       | 66,625           |       | —       |       | 66,625                                   |       |   | * |
| General and  administrative:                   |       |             |       |         |       |                                     |       |   |   |
| Deferred  compensation – repriced options |       | 1,219,349        |       | 3,385        |       | 1,215,964                                |       |   | * |
| Deferred  compensation – restricted stock |       | 372,151          |       | 399,249      |       | (27,098                                  | )          | (7 | )% |
| Other general  and administrative              |       | 5,540,140        |       | 4,826,793    |       | 713,347                                  |       | 15 | % |
|                                           |       | 25,824,713       |       | 19,487,684   |       | 6,337,029                                |       | 33 | % |
| Other expense,  net                            |       | 662,287          |       | 200,805      |       | 461,482                                  |       | 230 | % |
| Total                                          |       | $                | 26,487,000 |         | $          | 19,688,489                               |       | $ | 6,798,511 |   | 35 | % |
|                                                |            |                  |            |              |            |                                          |            |  |  |  |  |  |  |  |

 

----

* Not meaningful

 

Lease operating expensesfor the year ended December 31, 2003 increased 21% compared to the same periodof 2002 due to additional costs for 36 new wells drilled during the year andwells acquired late in 2003 and increased salt water disposal costs on theThibodeaux well. Average operating expenses for the year ended December 31,2003 were $0.33 per Mcfe as compared to $0.32 per Mcfe for the prior yearperiod.

 

Severance and ad valoremtaxes for the year ended December 31, 2003 increased 50% from 2002. Severancetax expense for 2003 was 67% higher than the prior year period as a result ofhigher revenue.  For the year ended December31, 2003, severance tax expense was approximately 5.3% of total revenuecompared to 5.7% of total revenue for the comparable 2002 period.  Ad valorem costs increased 3% from $419,400in 2002 to $433,300 in 2003 due primarily to the addition of the Miller andsouth Texas properties acquired late in 2003. On an equivalent basis, severanceand ad valorem taxes averaged $0.30 per Mcfe and $0.23 per Mcfe for the yearsended December 31, 2003 and 2002, respectively.

 

43

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DD&A and accretionfor the year ended December 31, 2003 totaled $13.6 million compared to $10.4million for the year ended December 31, 2002. Full cost depletion on our oil and natural gas properties totaled $12.9million for 2003 compared to $9.7 million in 2002. Depletion expense on a unitof production basis for the year ended December 31, 2003 was $1.59 per Mcfe,14% higher than the 2002 rate of $1.39 per Mcfe.  The higher depletion rate per Mcfe resultedin an increase in depletion expense of $1.6 million.  For the year ended December 31, 2003, higheroil and natural gas production compared to the prior year period resulted in anincrease in depletion expense of $1.6 million. The increase in the depletion rate was primarily due to a higher amortizablebase in 2003 compared to the prior year without a corresponding increase inreserves. Depreciation of furniture and fixtures totaled $603,698, a decreaseof 17% compared to the prior year total of $729,523 as a result of certainassets related to the previous office building becoming fully depreciated. Weadopted SFAS No. 143, effective January 1, 2003, and as a result, we recordedaccretion expense associated with our asset retirement obligation of $66,625for the year ended December 31, 2003 compared to zero in 2002 due the change inaccounting for asset retirement obligations (see Note 7 to our consolidatedfinancial statements).

 

Total general andadministrative (“G&A”) expenses for the year ended December 31, 2003 was$7.1 million, an increase of 36% compared to the prior year total of $5.2million.  Total G&A costs includedeferred compensation related to repriced options, deferred compensationrelated to restricted stock grants and other G&A costs.

 

Deferred compensationexpense consists of costs reported in accordance with FIN 44**and amortizationrelated to restricted stock awards. A FIN 44 charge of $1.2 million wasincurred for the year ended December 31, 2003 compared to a charge of $3,385 inthe comparable prior year period as a result of the variable accounting for theinteraction of the rising stock price and the exercise price of certainre-priced options.

 

Amortization related torestricted stock awards granted over the past two years totaled $372,151 and$399,249 for the years ended December 31, 2003 and 2002, respectively.

 

Other G&A expensesfor the year ended December 31, 2003, which does not include the deferredcompensation expenses discussed above, totaled $5.5 million, a 15% increasefrom the 2002 total of $4.8 million.  Theincrease in other G&A was attributable to higher audit and legal fees,higher franchise taxes, office moving costs and the settlement of a lawsuitrelated to seismic rights in April 2003 for $70,000.  In addition, we incurred costs associatedwith the Miller merger of approximately $279,400 (including retention, salariesand benefits, and integration costs) and software implementation costs tointegrate our production and land computer systems with accounting of$88,300.  These costs were partiallyoffset by lower rent and parking and lower reserve engineering fees compared tothe prior year periods.  For the yearsended December 31, 2003 and 2002, overhead reimbursement fees reduced G&Acosts by approximately $120,500 and $208,200, respectively. The Company capitalized$1.7 million and $1.5 million of general and administrative costs in 2003 and2002, respectively.  Other G&Aexpenses on a unit-of-production basis for the year ended December 31, 2003 was$0.68 per Mcfe compared to $0.69 per Mcfe for the comparable 2002 period.

 

Included in otherincome (expense) was interest expense of $678,800 for the year ended December31, 2003 compared to $227,800 in the same 2002 period.  Interest expense, including facility fees,was $923,300 for 2003 on weighted average debt of $23.0 million compared tointerest expense of $766,700 on weighted average debt of approximately $15.4million for 2002. Capitalized interest for the year ended December 31, 2003totaled $244,500 compared to $623,400 in the prior year.  At December 31, 2003, our unproved propertybalance was $5.0 million compared to $7.9 million at December 31, 2002,resulting in the lower capitalized interest for 2003.  Also included in interest expense for theyear ended December 31, 2002 was $84,500 representing amortization of deferredloan costs associated with our credit facility, which was fully amortized by2003.

 

Interest income totaled$16,500 for the year ended December 31, 2003 compared to $27,000 for the sameperiod in 2002.  The decrease in interestincome is due primarily to the overall decrease in the floating interest ratesat which the funds were invested in overnight money market funds.

 

An income tax provision was recorded for the yearended December 31, 2003 of $2.7 million as compared to $473,100 for the yearended December 31, 2002.  Due to changesin permanent differences, including meals and entertainment and compensationexpense, our effective tax rate changed from 38.7% in 2002 to 36.7% in 2003. As

 

44

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of December 31, 2003, approximately $50.1 million of net operating losscarryforwards had been accumulated or acquired.

 

Upon adoption of SFASNo. 143 on January 1, 2003, we recorded a cumulative effect of a change inaccounting principal of $357,800 (net of income taxes of $192,700) andaccretion expense, to recognize transition amounts for asset retirementobligations, asset retirement costs and accumulated depletion and accretion.

 

For the year endedDecember 31, 2003, we had net income of $4.4 million, or $0.45 basic earningsper share and $0.44 diluted earnings per share, as compared to net income of$749,700, or $0.08 basic and diluted earnings per share in 2002.  Basic weighted average shares outstanding increasedfrom approximately 9.4 million for the year ended December 31, 2002 to 9.7million in the comparable 2003 period. The increase was due primarily to options exercised and vesting ofrestricted stock during 2003. The impact of the shares issued in December 2003for the Miller transaction was not fully realized until 2004 since the mergerclosing and share issuance occurred late in 2003.

 

## ***Liquidity and Capital Resources***

 

Our primary ongoingsource of capital is the cash flow generated from our operating activitiessupplemented by borrowings under our credit facility.  Net cash generated from operating activitiesis a function of production volumes, commodity prices, which are inherentlyvolatile and unpredictable, operating efficiency and capital spending. Ourbusiness, as with other extractive industries, is a depleting one in which eachgas equivalent unit produced must be replaced or we, and a critical source ofour future liquidity, will shrink. Our overall production decline isapproximately 17% per year as we look to the future.  Less predictable than production declinesfrom our proved reserves is the impact of constantly changing oil and naturalgas prices on cash flows and, therefore capital budgets.  We attempt to mitigate the price risk withour hedging program. Reserves and production volumes are influenced, in part,by the amount of future capital expenditures. In turn, capital expenditures areinfluenced by many factors including drilling results, oil and gas prices,industry conditions, prices, availability of goods and services and the extentto which oil and gas properties are acquired.

 

For 2004, a significantsource of cash was the net proceeds of $47,810,000 that we received, beforedirect costs of $0.5 million, from our December 2004 offering of 3,500,000shares of our common stock.  In January2005, the underwriters exercised their over-allotment option for 525,000additional shares of our common stock resulting in an additional $7.2 millionof net proceeds to us. As of March 15, 2005, we have approximately $91.8million available under this current shelf registration statement.

 

Our primary needs forcash are for exploration, development and acquisition of oil and gasproperties, and the repayment of principal and interest on outstandingdebt.  We attempt to fund our explorationand development activities primarily through internally generated cash flowsand budget capital expenditures based on projected cash flows.  We routinely adjust capital expenditures inresponse to changes in oil and natural gas prices, drilling and acquisitioncosts, and cash flow.  We typically havefunded acquisitions from borrowings under our credit facility and cash flowfrom operations.  We have historicallyutilized net cash provided by operating activities, debt and equity as capitalresources to obtain necessary funding for all of our cash needs.

 

Some significant changesto working capital may also affect our liquidity in the short term. Theincrease in accrued fees for professional services and royalties payable atDecember 31, 2004 accounts for most of the increase in accrued liabilities.Therefore, we expect our short-term cash outflows for the first quarter toincrease as these liabilities come due.

 

The fair value of our outstanding hedge and derivativecontracts is reflected on the balance sheet, and we show an asset and aliability for the separate positions with each of our two counterparties. Ourasset position at December 31, 2004 is larger than it was at December 31, 2003contributing to the working capital increase, slightly offset by the liabilityposition that is included in the December 31, 2004 balance sheet. The hedge andderivative financial instrument liability represents the amount by which futurestrip commodity prices exceed the price caps on our contracts at the balance sheetdate. The hedge and derivative financial instrument asset represents the amountby

 

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which strip commodityprices are lower than the price floors on our contracts at the balance sheetdate. Should commodity prices increase or decrease, the applicable positionswould change accordingly and the unrealized losses that are reflected inrevenue and the unrealized gains reflected in other comprehensive income couldpossibly reduce or result in gains or losses, respectively. When hedges andderivatives require cash settlement, the Company is receiving higher cashinflows on the sale of production at higher prices, therefore the use of thosefunds would adequately cover any derivative and hedge payments when they comedue.

 

We havehistorically used our credit facility to supplement any deficiencies betweenoperating cash flow and capital expenditures. We had $20.0 million outstandingunder the credit facility at December 31, 2004, which was subsequently reduced inJanuary 2005 to $13.0 million with proceeds from the underwriter’sover-allotment option to our December 2004 public stock offering (seediscussion below) and further to $10.0 million from cash on hand in February.The maturity for this credit facility is December 31, 2006.

 

After consideringthe impact of these working capital changes and our forecasts of future resultsof operations, we believe that cash flows from operating activities, assupplemented by borrowings on our credit facility, combined with our ability tocontrol the timing of the majority of our future exploration and developmentrequirements will provide us with the flexibility and liquidity to meet ourplanned capital requirements for 2005. In addition, our credit facility had$45.0 million available at December 31, 2004 ($52.0 million after net proceedsfrom the underwriter over-allotment option exercise in January 2005 were usedto repay debt) for general corporate purposes, exploratory and developmentaldrilling and acquisitions of oil and gas properties.

 

During 2004, the rise inour stock price contributed to significant exercises of warrants and stockoptions, from which we have realized increased cash flows from financingactivities. On March 2, 2004, Mr. Elias, our Chairman and Chief ExecutiveOfficer, exercised outstanding warrants for 45,000 shares of common stock,which resulted in proceeds to us of approximately $240,750. Increased activityin stock option exercises has also resulted in proceeds to us of approximately$2.0 million for the year ended December 31, 2004. We typically do not rely onproceeds from the exercise of warrants and stock options to sustain ourbusiness as they are unpredictable events.

 

We had cash and cashequivalents at December 31, 2004 of $2.3 million consisting primarily ofshort-term money market investments, as compared to $1.3 million at December31, 2003.  Working capital was $9.0million as of December 31, 2004, as compared to $0.9 million at December 31,2003.

 

*NetCash Provided By Operating Activities*

 

Cash flows provided byoperating activities were $42.3 million, $23.9 million and $10.4 million, forthe years ended December 31, 2004, 2003, and 2002, respectively.  The significant increase in cash flowsprovided by operating activities for the year ended December 31, 2004 comparedto 2003 was primarily due to higher total revenues partially offset by higheroperating expense. Revenue for 2004 increased 90% over 2003. The increase incash flows provided by operating activities in 2003 as compared to 2002 was dueprimarily to higher oil and gas revenue partially offset by higher operatingexpense.

 

Net cash generated fromoperating activities is a function of commodity prices, which are inherentlyvolatile and unpredictable, production and capital spending.  Our business, as with other extractiveindustries, is a depleting one in which each gas equivalent produced must bereplaced or we, and a critical source of our future liquidity, will shrink. Ourability to prevent shrinkage will be affected in the future by the successesand/or failures of our exploration, production and acquisition activities. Lesspredictable than production declines from our proved reserves is the impact ofconstantly changing oil and natural gas prices on cash flows and, thereforecapital budgets.

 

For these reasons, weonly forecast, for internal use by management, an annual cash flow. We doanalyze contingent well opportunities that may extend further than one year,but do not rely on them for sustaining our business. These annual forecasts arerevised monthly and capital budgets are reviewed by management and adjusted aswarranted by market conditions. Longer-term cash flow and capital spending projections are neitherdeveloped nor used by management to operate our business.

 

In the event such capitalresources are not available to us, our drilling and other activities may becurtailed. See *ITEMS 1 AND 2. “BUSINESS AND PROPERTIES –*RISK FACTORS – Our operations havesignificant capital requirements.”

 

46

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*NetCash Used In Investing Activities*

 

***We reinvest a substantial portion of our cash flows in ourdrilling, acquisition, land and geophysical activities.  As a result, we used $89.4 million ininvesting activities during 2004.  Capitalexpenditures for the year ended December 31, 2004 were partially offset by$60,000 of proceeds from the sale of one well and a gas cooler during the year.Capital expenditures of $45.7 million were attributable to the drilling of 49gross wells, 40 of which were successful. Acquisition costs totaled $40.0million for the year ended December 31, 2004, which includes $39.8 millionrelated to the Contango Asset Acquisition. Other spending includes $2.6 millionin expenditures attributable to land holdings and $0.6 million for increasedseismic data and other geological and geophysical expenditures.  The remaining capital expenditures wereassociated with computer hardware, office furniture and equipment for the expansioninto additional office space.***

*** ***

***During the year ended December 31, 2003, we used $28.1million in investing activities. Capital expenditures of $33.6 million for theyear ended December 31, 2003, were partially offset by $5.2 million of cashreceived in the Miller merger net of merger costs incurred and $0.3 million inproceeds from the sale of oil and gas properties during 2003.  Capital expenditures of $18.3 million wereattributable to the drilling of 36 gross wells, 28 of which were successful.  Acquisition costs, excluding Miller, totaled$12.3 million for the year ended December 31, 2003, and an additional $0.8million in expenditures was attributable to land holdings, including seismicdata and other geological and geophysical expenditures.  The remaining capital expenditures were associatedwith computer hardware and office equipment.***

*** ***

***During the year ended December 31, 2002, we used $19.3million in investing activities.  Capitalexpenditures of $19.6 million for the year ended December 31, 2002, werepartially offset by $0.4 million in proceeds from the sale of oil and gasproperties during 2003.  Capitalexpenditures of $12.7 million were attributable to the drilling of 13 grosswells, 11 of which were successful. Acquisition costs totaled $1.4 million for the year ended December 31,2002, and an additional $5.5 million in expenditures was attributable to landholdings, including $1.0 million for increased seismic data and othergeological and geophysical expenditures. The remaining capital expenditures were associated with computerhardware and office equipment.***

*** ***

Due to our activeexploration, development and acquisition activities, we have experienced andexpect to continue to experience substantial working capital requirements.  We currently anticipate capital expenditures in2005 to be approximately $63 million. Approximately $51.7 million is allocatedto our expected drilling and production activities; $7.9 million is allocatedto land and seismic activities; and $3.3 million relates to capitalizedinterest, G&A and other. We intend to fund these capital expenditures, andother commitments and working capital requirements with expected cash flow fromoperations and, to the extent necessary, other financing activities. Shouldthere be a change in our pricing or production assumptions, we believe that wehave sufficient financial flexibility from other financing activities to meetour financial obligations as they come due, and we would recommend to our Boardan adjustment to our capital expenditures program accordingly so as to avoidunnecessary incremental borrowings that may be needed for acquisitions. We donot explicitly budget for acquisitions; however, we do expect to spendconsiderable effort evaluating acquisition opportunities.  We expect to fund acquisitions through traditionalreserve-based bank debt and/or the issuance of equity and, if required, throughadditional debt and equity financings.

 

*NetCash Provided By Financing Activities*

 

Cash flows provided byfinancing activities totaled $48.1 million for the year ended December 31,2004. We had $27.0 million in borrowings and $28.0 million in repayments underour credit facility. We incurred loan costs of approximately $0.4 million inestablishing our new credit facility. In addition, we received $2.3 million inproceeds from the issuance of common stock related to options and warrantsexercised in 2004, and we completed a public offering of common stock under ourcurrent shelf registration (see discussion below) in December 2004 thatprovided $47.2 million of net proceeds, after direct costs. For the year endedDecember 31, 2003, cash flows provided by financing activities totaled $2.9million including $10.7 million in borrowings and $10.2 million in repaymentsunder our credit facility. In addition, we received $2.4 million in proceedsfrom the issuance of common stock related to options exercised in 2003 as aresult of the increase in our stock price. For the year ended December 31, 2002, cash flows provided by financingactivities totaled $10.6 million, including $11.0 million in borrowings and

 

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$0.5 million inrepayments under our credit facility. In addition, we received $0.1 million inproceeds from the issuance of common stock related to options exercised in2003.

 

In connection with theDecember 2004 common stock offering, the underwriters exercised theirover-allotment option in January 2005, which provided funds that were used toreduce our outstanding debt. The combination of unused debt capacity and ourcurrent shelf registration will allow us the financial flexibility toparticipate in larger acquisitions and complete our capital programs as we moveinto 2005. As of December 31, 2004, we had $45.0 million of unused borrowingcapacity under our credit facility.

 

***CreditFacility***

 

In March 2004, theCompany entered into a new amended and restated credit facility (the “CreditFacility”), effective December 31, 2003, which permits borrowings up to thelesser of (i) the borrowing base and (ii) $100 million. The Credit Facilitymatures December 31, 2006 and is secured by substantially all of the Company’sassets. Borrowings under the Credit Facility bear interest at a rate equal toprime plus 0.50% or LIBOR plus 2.25%.  Asof December 31, 2004, $20.0 million in borrowings were outstanding under theCredit Facility and our interest rate was 5.75%.

 

Effective December 2004,the borrowing base under the Credit Facility was increased from $48.0 millionto $65.0 million as a result of the Contango Asset Acquisition and our drillingactivities since the last redetermination. Based on the increase, our availableborrowing capacity at December 31, 2004 was $45.0 million. We expect ourborrowing base to be redetermined in April 2005 and semiannually thereafter.

 

The Credit Facilityprovides for certain restrictions, including but not limited to, limitations onadditional borrowings, sales of oil and natural gas properties or othercollateral, and engaging in merger or consolidation transactions. The CreditFacility also prohibits dividends and certain distributions of cash orproperties and certain liens.  The CreditFacility also contains the following financial covenants, among others:

 

•                  TheEBITDAX to Interest Expense ratio requires that the ratio of (a) ourconsolidated EBITDAX (defined as EBITDA plus similar non-cash items andexploration and abandonment expenses for such period) for the four fiscalquarters then ended to (b) our consolidated interest expense for the fourfiscal quarters then ended, to not be less than 3.5 to 1.0.

•                  TheWorking Capital ratio requires that the amount of our consolidated currentassets less our consolidated current liabilities, as defined in the agreement,be at least $1.0 million. For the purposes of calculating the Working Capital ratio,current assets is adjusted for unused capacity under credit agreement andhedging and derivative assets and current liabilities is adjusted forderivative and hedging liabilities and asset retirement obligations.

•                  TheMaximum Leverage ratio requires that the ratio, as of the last day of anyfiscal quarter, of (a) Total Indebtedness (as defined in the Credit Facility)as of such fiscal quarter to (b) an amount equal to consolidated EBITDAX forthe two quarters then ended times two, not be greater than 3.0 to 1.0.

 

Consolidated EBITDAX is acomponent of negotiated covenants with our lender and is presented here as partof the Company’s disclosure of its covenant obligations.

 

***Shelf Registration Statement***

 

We filed a $150 million shelf registration statement with the SEC, which became effective in May 2004. Under the shelf registration statement, we may issue, from time to time, any combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities in one or more offerings to those persons who agree to purchase our securities. Net proceeds, terms and pricing of the offering of securities issued under the shelf registration statement will be determined at the time of the offerings. The shelf registration statement does not provide assurance that we will or could sell any such securities. Our ability to utilize our shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities, preferred stock, common

 

48

 

stock or warrants for debt securities or equity securities will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.

 

We completed an offering on December 21, 2004 of 3.5 million shares of our common stock under our shelf registration statement, which generated net proceeds to us, before direct costs of the offering, of $47.8 million. These funds were used to finance the Contango Asset Acquisition preliminary adjusted purchase price of $43.2 million and fund the costs of the offering and other general corporate purposes. On January 5, 2005, the underwriters exercised their over-allotment option for an additional 525,000 shares of common stock, which generated net proceeds to us of $7.2 million. These funds were used to reduce our outstanding debt. Each of these sales was made under our shelf registration statement such that at March 15, 2005, we had approximately$91.8 million remaining for issuance under our shelf registration.

 

***Off Balance Sheet Arrangements***

 

The Company currentlydoes not have any off balance sheet arrangements.

 

***Contractual Cash Obligations***

 

The following tablesummarizes our contractual cash obligations as of December 31, 2004 by paymentdue date:

 

 
| ** **                                 | ** ** | **Total**          | ** ** | **Less than  1 Year** | ** ** | **1-3 Years** | ** ** | **4-5  Years** | ** ** | **After 5  Years** | ** ** |
|--------------------------------------------|------------|--------------------|------------|-----------------------|------------|---------------|------------|----------------|------------|--------------------|------------|
| ** **                                 | ** ** | **(In thousands)** | ** ** |
| Long-term debt(1)                          |       | $                  | 20,000     |                  | $          | —        |       | $              | 20,000     |               | $          | — |   | $ | — |   |
| Operating leases                           |       | 5,356              |       | 629                   |       | 1,874         |       | 1,245          |       | 1,608              |       |
| Total  contractual cash obligations (2)(3) |       | $                  | 25,356     |                  | $          | 629           |       | $              | 21,874     |               | $          | 1,245 |   | $ | 1,608 |   |
|                                            |            |                    |            |                       |            |               |            |                |            |                    |            |  |  |  |  |  |  |  |

 

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(1)   Excludes amounts for interest expense payableupon outstanding debt.  Long-term debtoutstanding under our credit facility is subject to floating interest rates(see note 10 to our consolidated financial statements) and payable on the lastday of each calendar month while any loan amounts remain outstanding.

(2)   TheCompany did not have any capital leases or purchase obligations as of December31, 2004.

(3)   TheCompany has not included its ARO Liability here because historically the actualcash outlay is minimized significantly by the salvage value. In accordance withSFAS No. 143, we do not account for salvage value on our Balance Sheet, but wedo not expect to realize the total value that we have accrued.

 

**Risk Management Activities –Derivatives & Hedging**

 

Due to the instability ofoil and natural gas prices, we may enter into, from time to time, price-riskmanagement transactions (e.g., swaps, collars and floors) for a portion of ouroil and natural gas production to achieve a more predictable cash flow, as wellas to reduce exposure from commodity price fluctuations.  While the use of these arrangements limit ourability to benefit from increases in the price of oil and natural gas, it alsoreduces our potential exposure to adverse price movements.  Our arrangements, to the extent we enter intoany, apply to only a portion of our production, provide only partial priceprotection against declines in oil and natural gas prices and limits ourpotential gains from future increases in prices. We also use price-riskmanagement transactions to protect forward pricing as a bidding strategy withrespect to acquisition offers and execution. None of these instruments are usedfor trading purposes. On a quarterly basis, our management sets all of ourprice-risk management policies, including volumes, types of instruments andcounterparties. These policies are implemented by management through theexecution of trades by the Chief Financial Officer after consultation andconcurrence by the President and Chairman of the Board.  Our Board of Directors monitors the Company’sprice-risk management policies and trades.

 

All of these price-riskmanagement transactions are considered derivative instruments and accounted forin accordance with SFAS No. 133, *“Accountingfor Derivative Instruments and Hedging Activities”*. These derivativeinstruments are intended to hedge our price risk and may be considered hedgesfor economic purposes, but certain of these transactions may not qualify forspecial cash flow hedge accounting. Therefore, depending on the type oftransaction and the circumstances, different accounting treatment may apply tothe timing and location of the income statement impact, but all derivatives arerecorded on the balance sheet at fair value. The following table provides

 

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additional informationregarding the Company’s various derivative and hedging transactions that wererecorded at fair value on the balance sheet as of December 31, 2004.

 
| Fair value of  contracts outstanding at December 31, 2003                               |   | $         | 120,801   |   |
|-----------------------------------------------------------------------------------------|--------|-----------|-----------|--------|
| Contracts  realized or otherwise settled during the period                              |   | (120,801  | )         |
| Fair value of  new contracts when entered into during 2004:                             |   |      |      |
| Asset                                                                                   |   | 1,824,790 |      |
| Liability                                                                               |   | (468,308  | )         |
| Changes in fair  values attributable to changes in valuation techniques and assumptions |   | —    |      |
| Other changes in  fair values                                                           |   | —    |      |
| Fair values of  contracts outstanding at December 31, 2004                              |   | $         | 1,356,482 |   |

 

The following table details the fair value of ourcommodity-based derivative and hedging contracts by year of maturity andvaluation methodology as of December 31, 2004.

 
| ** **                                           | ** ** | **Fair Value of Contracts at December 31, 2004** | ** ** |
|------------------------------------------------------|------------|--------------------------------------------------|------------|
| **Source of Fair Value**                             | ** ** | **Maturity less  than 1 year**                   | ** ** | **Maturity 1-3  years** | ** ** | **Maturity 4-5  years** | ** ** | **Maturity in  excess of  5 years** | ** ** | **Total fair  value** | ** ** |
| Prices actively  quoted:                             |       | —                                           |       | — |   | — |   | — |   | — |   |
| Prices provided  by other external sources:          |       |                                             |       |   |   |   |   |   |   |   |   |
| Asset                                                |       | 1,824,790                                        |       | — |   | — |   | — |   | 1,824,790 |   |
| Liability                                            |       | (468,308                                         | )          | — |   | — |   | — |   | (468,308 | ) |
| Prices based on  models and other valuation methods: |       | —                                           |       | — |   | — |   | — |   | — |   |
| Total                                                |       | $                                                | 1,356,482  |   | $ | — |   | $ | — |   | $ | — |   | $ | 1,356,482 |   |
|                                                      |            |                                                  |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

**Tax Matters**

 

At December 31, 2004, wehave cumulative net operating loss carryforwards (“NOLs”) for federal incometax purposes of approximately $73.9 million, including $17.4 million of NOLsacquired in the Miller merger that expire beginning 2012 through 2022. Theestimated NOLs presented herein assume that certain items, primarily intangibledrilling costs, have been written off for tax purposes in the current year.However,  we have not made a finaldetermination if an election will be made to capitalize all or part of theseitems for tax purposes in the future.

 

**Recently Issued****Accounting Pronouncements**

 

In December 2004, theFASB issued SFAS No. 123(R), “*Share-BasedPayment.*” This statement requires companies to measure the cost ofemployee services in exchange for an award of equity instruments based on agrant-date fair value of the award (with limited exceptions), and that costmust generally be recognized over the vesting period. SFAS No. 123(R) amendsthe original SFAS No. 123 and 95 that had allowed companies to choose betweenexpensing stock options or showing pro forma disclosure only. This statementeliminates the ability to account for share-based compensation transactionsusing APB Opinion No. 25. We currently account for our stock-based compensationplans under the principles prescribed by APB Opinion No. 25. Accordingly,no stock option compensation cost is reflected in net income, as all optionsgranted under the plan had an exercise price equal to the market value of theunderlying common stock on the date of grant. The adoption of SFAS No. 123(R)will impact our results of operations, but will have no impact on our overallfinancial position. SFAS No. 123(R) becomes effective as of the beginning ofthe first interim or annual reporting period that begins after June 15, 2005.We anticipate adopting the provisions of SFAS No. 123(R) in the thirdquarter of 2005 using the modified prospective method for transition. Underthis method we will recognize compensation expense for all stock-based awardsgranted or modified on or after July 1, 2005, as well as any previouslygranted awards that are not fully vested as of July 1, 2005. Compensationexpense will be measured based on the fair value of the awards previouslycalculated in developing the pro forma disclosures in accordance with theprovisions of SFAS No. 123. We expect the impact to be an increase indeferred compensation expense of approximately $80,000 to $100,000 for 2005.SFAS No. 123(R) also requires the benefits of tax deductions in excess ofrecognized compensation cost to be reflected as a financing cash flow, ratherthan as an operating cash flow as currently required. We did not recognize anyexcess tax deductions during 2004, 2003 or 2002 in connection with the exerciseof stock options.

 

        InSeptember 2004, the SEC issued SAB No. 106, *“Interactionof Statement 143 and the Full Cost Rules,”* which we adopted in thefourth quarter of 2004 with no impact on our financial statements. Inaccordance with SAB No. 106*,*theamortizable base used to calculate unit-of production depletion includesestimated future development and dismantlement costs, and restoration andabandonment costs, net of estimated salvage values.

 

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***ITEM7A.  QUALITATIVE AND QUANTITATIVEDISCLOSURES ABOUT MARKET RISK***

 

We are exposed to market risk from changes in interestrates and commodity prices.  We use acredit facility, which has a floating interest rate, to finance a portion ofour operations. We are not subject to fair value risk resulting from changes inour floating interest rates.  The use offloating rate debt instruments provide a benefit due to downward interest ratemovements but does not limit us to exposure from future increases in interestrates.  Based on the year-end December31, 2004 outstanding borrowings and a floating interest rate of 5.75%, a 10%change in interest rate would result in an increase or decrease of interestexpense of approximately $110,000 on an annual basis.

 

In the normal course of business we enter into hedgingtransactions, including commodity price collars, swaps and floors to mitigateour exposure to commodity price movements, but not for trading or speculativepurposes.   During 2003 and 2004, due tothe instability of prices and to achieve a more predictable cash flow, we putin place several natural gas and crude oil collars for a portion of our 2004production. During 2004, we put in place several natural gas and crude oilcollars covering 2005 production. Please refer to Note 9 to our consolidatedfinancial statements. While the use of these arrangements may limit the benefitto us of increases in the price of oil and natural gas, it also limits thedownside risk of adverse price movements. The following is a list of contracts outstanding at December 31, 2004:

 
| **Transaction Date** | ** ** | **Transaction Type**   | ** ** | **Beginning** | ** ** | **Ending** | ** ** | **Price  Per Unit** | ** ** | **Volumes Per  Day** | ** ** |
|----------------------|------------|------------------------|------------|---------------|------------|------------|------------|---------------------|------------|----------------------|------------|
| ** **           | ** ** | ** **             | ** ** | ** **    | ** ** | ** ** | ** ** | ** **          | ** ** | ** **           | ** ** |
| ***Natural  Gas:***  |       |                   |       |          |       |       |       |                |       |                 |       |
| 05/04                |       | Natural Gas Collar(1)  |       | 01/01/05      |       | 03/31/05   |       | $5.00-$10.39        |       | 10,000 MMbtu         |       |
| 07/04                |       | Natural Gas Collar(1)  |       | 04/01/05      |       | 06/30/05   |       | $5.00-$7.53         |       | 10,000 MMbtu         |       |
| 07/04                |       | Natural Gas Collar(1)  |       | 07/01/05      |       | 09/30/05   |       | $5.00-$7.67         |       | 10,000 MMbtu         |       |
| 10/04                |       | Natural Gas Collar(1)  |       | 01/01/05      |       | 12/31/05   |       | $6.00-$9.52         |       | 10,000 MMbtu         |       |
|                 |       |                   |       |          |       |       |       |                |       |                 |       |
| ***Crude  Oil:***    |       |                   |       |          |       |       |       |                |       |                 |       |
| 05/04(08/04)         |       | Crude Oil Collar(2)(3) |       | 01/01/05      |       | 12/31/05   |       | $35.00-$40.00       |       | 200/290 Bbl          |       |

 

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(1)                TheCompany’s current hedging activities for natural gas were entered into on a perMMbtu delivered price basis, using the Houston Ship Channel Index, withsettlement for each calendar month occurring five business days following theexpiration date.

(2)                Hedge accountingis not applied to the Company’s collars on crude oil, which were entered intoon a per barrel delivered price basis, using the West Texas Intermediate Index,with settlement for each calendar month occurring five business days followingthe expiration date. The change in fair value is reflected in revenue for theyear ended December 31, 2004.

(3)                In August 2004,the Company replaced the hedge contract that was outstanding at June 30, 2004with a new contract that changes the volume and pricing terms. The put optionis on 200 Bbl/D and the call option is on 290 Bbl/D. This transaction wascompleted at no additional cost to the Company.

 

At December 31, 2004, the fair value of theoutstanding hedge and derivative contracts was a net asset of approximately$1.4 million (See *ITEM 7. “MANAGEMENT’SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS –*RISK MANAGEMENTACTIVITIES – HEDGING & DERIVATIVES*”)*. A 10% change in the commodity price per unit, as long asthe price is either above the ceiling or below the floor price of eachcontract, would cause the fair value total of the outstanding net assetposition to increase or decrease by approximately $234,200.

 

***ITEM8.  FINANCIAL STATEMENTS AND SUPPLEMENTARYDATA***

 

See the ConsolidatedFinancial Statements and Supplementary information listed in the accompanyingIndex to Consolidated Financial Statements and Supplementary Information onpage F-1 herein.

 

***ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTSON ACCOUNTING AND FINANCIAL DISCLOSURES***

*** ***

None.

 

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***ITEM 9A. CONTROLS AND PROCEDURES***

 

We maintain disclosure controls and procedures thatare designed to provide reasonable assurance that information required to bedisclosed by us in the reports that we file or submit to the Securities andExchange Commission under the Securities Exchange Act of 1934, as amended, isrecorded, processed, summarized and reported within the time periods specifiedby the Commission’s rules and forms, and that information is accumulated andcommunicated to our management, including Chief Executive Officer and our ChiefFinancial Officer, as appropriate to allow timely decisions regarding requireddisclosure. 

 

We recently discovered an error in a spreadsheetapplication, which was designed to eliminate intercompany balances. As a resultof the error, amounts accumulated in the property account for one subsidiarywere also included as an accrued capital expenditure by another subsidiary andinadvertently not eliminated in consolidation. This caused property balances tobe overstated. This error in the property balance also impacted our computationof depletion expense and therefore operating expenses, operating income, incometax expense, net income and earnings per share. As a result of the error, werestated our September 30, 2004 financial statements, as reflected in AmendmentNo. 1 to our Form 10-Q for the quarterly period ended September 30, 2004 andcorrected our earnings release for December 31, 2004. The error arose as aresult of a change in accounting processes that occurred during the secondquarter of 2004 and therefore prior year results were not affected and secondquarter 2004 results were not materially affected. In January 2005, weeffectively corrected the problem by re-instituting the accounting process wehad used prior to the second quarter of 2004. Management has concluded, basedon the circumstances involving the spreadsheet error discussed above, that asof December 31, 2004, a material weakness in internal control over financialreporting existed with respect to the design of the Company’s controls over theelimination of intercompany balances and transactions.

 

In accordance with Exchange Act Rules 13a-15 and 15d-15,we carried out an evaluation, under the supervision and with the participationof management, including our Chief Executive Officer and Chief FinancialOfficer, of the effectiveness of our disclosure controls and procedures as ofthe end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and ChiefFinancial Officer concluded that, due to the material weakness discussed above,our disclosure controls and procedures were not effective as of December 31,2004.

 

We are relying on theexemption provided by Order of the SEC in Release No. 34-50754 (the “Order”).  Accordingly we have not included in thisAnnual Report on Form 10-K filing either “Management’s annual report oninternal control over financial reporting,” required by Item 308(a) ofRegulation S-K, or the related “Attestation report of the registered publicaccounting firm,” required by Item 308(b) of Regulation S-K.  We will file both of these reports pursuantto an Amendment to our Form 10-K on or before May 2, 2005, in accordance withthe Order.  As a result of the materialweakness discussed above, management’s report on internal control will statethat internal control over financial reporting was not effective at December31, 2004 and BDO Seidman, LLP has advised us that they expect that their reporton management’s assessment of internal control over financial reporting willalso indicate that internal control over financial reporting was ineffective asof that date. As a result of our ongoing evaluation of internal control overfinancial reporting and in preparation for that report, additional problems maybe identified which result in disclosure controls and procedures not beingeffective at December 31, 2004 for other reasons.

 

There has been no change in our internal controls overfinancial reporting that occurred during the three months ended December 31,2004 that has materially affected, or is reasonably likely to materially affect,our internal controls over financial reporting.

 

***ITEM 9B. OTHER INFORMATION***

 

None.

 

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**PART III**

 

***ITEM10.  DIRECTORS AND EXECUTIVE OFFICERS OFTHE REGISTRANT***

 

The information regardingdirectors and executive officers required under *ITEM 10*will be contained within the definitive Proxy Statement for the Company’s 2005Annual Meeting of Shareholders (the “Proxy Statement”) under the headings “Electionof Directors,” “Standing Committees, Board Organization, Director Nominations andMeetings” and “Compliance with Section 16(a) of the Exchange Act” and isincorporated herein by reference.  TheProxy Statement will be filed pursuant to Regulation 14A with the Securitiesand Exchange Commission not later than 120 days after December 31, 2004.  Pursuant to Item 401(b) of Regulation S-Kcertain of the information required by this item with respect to executiveofficers of the Company is set forth in Part I of this report.

 

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

 

***ITEM 11.  EXECUTIVE COMPENSATION***

 

The information requiredby *ITEM 11* will be contained in the ProxyStatement under the headings “ExecutiveCompensation”, “Summary Compensation Table”,  “Option/SAR Grants”, “Option/SAR Exercises and2004 Year-End Option/SAR Values”, “401(k) Employee Savings Plan”, “EmploymentAgreements and Change of Control Agreements”, “Compensation CommitteeInterlocks and Insider Participation”, “Performance Graph” and “CompensationCommittee Report on Executive Compensation” and is incorporated hereinby reference.

 

***ITEM12.  SECURITY OWNERSHIP OF CERTAINBENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS***

 

The information requiredby *ITEM 12* will be contained in the ProxyStatement under the headings “Security Ownership of Certain Beneficial Ownersand Management” and “Equity Compensation Plan Information” and is incorporatedherein by reference.

 

***ITEM13.  CERTAIN RELATIONSHIPS AND RELATEDTRANSACTIONS***

 

The information requiredby *ITEM 13* will be contained in the ProxyStatement under the heading “Certain Transactions “ and is incorporated hereinby reference.

 

***ITEM14. PRINCIPAL ACCOUNTANT FEES AND SERVICES***

 

The information requiredby *ITEM 14* will be contained in the ProxyStatement under the heading “Approval of Appointment of Independent PublicAccountants” and is incorporated herein by reference.

 

53

----

 

**PART IV**

 

***ITEM15.  EXHIBITS AND FINANCIAL STATEMENTSCHEDULES***

 
| (a)    |   | Financial  Statements and Schedules:                                    |
|--------|--------|-------------------------------------------------------------------------|
|   |   | 1.                                                                      |   | Financial  Statements:  See Index to the  Consolidated Financial Statements and Supplementary Information immediately  following the signature page of this report. |
|   |   |                                                                    |   |   |
|   |   | 2.                                                                      |   | Financial  Statement Schedule: See Index to the Consolidated Financial Statements and  Supplementary Information immediately following the signature page of this  report. |
|   |   |                                                                    |   |   |
| (b)    |   | Exhibits:  The following documents are filed as exhibits to this report |
|   |   | 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)). |
|   |   |                                                                    |   |   |
|   |   | 2.2  —                                                             |   | Agreement  and Plan of Merger dated as of May 28, 2003 among Edge Petroleum Corporation,  Edge Delaware Sub Inc. and Miller Exploration Company (Miller”) (Incorporated  by reference from Annex A to the Joint Proxy Statement/Prospectus contained  in the Company’s Registration Statement on Form S-4/A filed on October 31,  2003 (Registration No. 333-106484)). |
|   |   |                                                                    |   |   |
|   |   | 2.3  —                                                             |   | Asset  Purchase Agreement by and among Contango STEP, L.P., Contango Oil & Gas  Company, Edge Petroleum Exploration Company and Edge Petroleum Corporation  dated October 7, 2004 (Incorporated by reference from exhibit 2.1 to the  Company’s Current Report on Form 8-K filed October 12, 2004). |
|   |   |                                                                    |   |   |
|   |   | 3.1  —                                                             |   | Restated  Certificate of Incorporation of the Company (Incorporated by reference from  exhibit 3.1 to the Company’s Registration Statement on Form S-1/A filed on  February 5, 1997 (Registration No. 333-17267)). |
|   |   |                                                                    |   |   |
|   |   | 3.2  —                                                             |   | Certificate  of Amendment to the Restated Certificate of Incorporation of the Company  (Incorporated by reference from exhibit 3.1 to the Company’s Registration  Statement on Form S-1/A filed on February 5, 1997 (Registration No.  333-17267)). |
|   |   |                                                                    |   |   |
|   |   | 3.3  —                                                             |   | 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). |
|   |   |                                                                    |   |   |
|   |   | 3.4  —                                                             |   | 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). |
|   |   |                                                                    |   |   |
|   |   | 3.5  —                                                             |   | Second  Amendment to Bylaws of the Company on May 7, 2003 (Incorporated by reference  from exhibit 3.4 to the Company’s Quarterly Report on Form 10-Q for the  quarterly period ended March 31, 2003). |
|   |   |                                                                    |   |   |
|   |   | 4.1  —                                                             |   | Third  Amended and Restated Credit Agreement dated December 31, 2003 among Edge  Petroleum Corporation, Edge Petroleum Exploration Company, Edge Petroleum  Operating Company, Inc., Miller Oil Corporation, and Miller Exploration  Company, as borrowers, the lenders thereto and Union Bank of California,  N.A., a national banking association, as Agent (Incorporated by reference  from Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the  quarterly period ended March 31, 2004). |
|   |   |                                                                    |   |   |
|   |   | 4.2  —                                                             |   | 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). |
|        |        |                                                                         |  |  |  |  |

 

54

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|   |   | 4.3  —      |   | Registration  Rights Agreement by and among Edge Petroleum Corporation, Guardian Energy  Management Corp., Kelly E. Miller and the Debra A. Miller Trust, dated  December 4, 2003 (Incorporated by reference from exhibit 4.2 to the Company’s  Registration Statement on Form S-3 filed on February 3, 2004 (Registration  No. 333-112462)). |
|--------|--------|------------------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |             |   |                                                                                                                                                                                                                                                                                                                                               |
|   |   | 4.4  —      |   | Miller  Exploration Company Stock Option and Restricted Stock Plan of 1997  (Incorporated by reference from exhibit 10.1(a) to Miller Exploration  Company’s Annual Report on Form 10-K for the year ended December 31, 1997 (File  No. 000-23431)).                                                                                          |
|   |   |             |   |                                                                                                                                                                                                                                                                                                                                               |
|   |   | 4.5  —      |   | Amendment  No. 1 to the Miller Exploration Company Stock Option and Restricted Stock  Plan of 1997 (Incorporated by reference to Exhibit 4.2 from Miller  Exploration Company’s Registration Statement on Form S-8 filed on April 11,  2001 (Registration No. 333-58678)).                                                                    |
|   |   |             |   |                                                                                                                                                                                                                                                                                                                                               |
|   |   | 4.6  —      |   | Amendment  No. 2 to the Miller Exploration Company Stock Option and Restricted Stock  Plan of 1997 (Incorporated by reference from Exhibit 4.3 to Miller  Exploration Company’s Registration Statement on Form S-8 filed on April 11,  2001 (Registration No. 333-58678)).                                                                    |
|   |   |             |   |                                                                                                                                                                                                                                                                                                                                               |
|   |   | 4.7  —      |   | Form  of Miller Stock Option Agreement (Incorporated by reference from exhibit  10.1(b) to Miller Exploration Company’s Annual Report on Form 10-K for the  year ended December 31, 1997 (File No. 000-23431)).                                                                                                                               |
|   |   |             |   |                                                                                                                                                                                                                                                                                                                                               |
|   |   | †10.1— |   | Form  of Indemnification Agreement between the Company and each of its directors  (Incorporated by reference from exhibit 10.7 to the Company’s Registration  Statement on Form S-4 (Registration No. 333-17269)).                                                                                                                            |
|   |   |             |   |                                                                                                                                                                                                                                                                                                                                               |
|   |   | †10.2— |   | Stock  Option Plan of Edge Petroleum Corporation, a Texas corporation (Incorporated  by reference from exhibit 10.13 to the Company’s Registration Statement on  Form S-4 (Registration No. 333-17269)).                                                                                                                                      |
|   |   |             |   |                                                                                                                                                                                                                                                                                                                                               |
|   |   | †10.3— |   | Employment  Agreement dated as of November 16, 1998, by and between the Company and John  W. Elias (Incorporated by reference from 10.12  to the Company’s Annual Report on Form 10-K  for the year ended December 31, 1998).                                                                                                            |
|   |   |             |   |                                                                                                                                                                                                                                                                                                                                               |
|   |   | †10.4— |   | Incentive  Plan of Edge Petroleum Corporation as Amended and Restated Effective as of  June 1, 2004 (Incorporated by reference from exhibit 10.9 to the Company’s  Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004).                                                                                               |
|   |   |             |   |                                                                                                                                                                                                                                                                                                                                               |
|   |   | †10.5— |   | Edge  Petroleum Corporation Incentive Plan “Standard Non-Qualified Stock Option  Agreement” by and between Edge Petroleum Corporation and the Officers named  therein (Incorporated by reference from exhibit 10.2 to the Company’s  Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).              |
|   |   |             |   |                                                                                                                                                                                                                                                                                                                                               |
|   |   | †10.6— |   | Edge  Petroleum Corporation Incentive Plan “Director Non-Qualified Stock Option  Agreement” by and between Edge Petroleum Corporation and the Directors named  therein (Incorporated by reference from exhibit 10.3 to the Company’s  Quarterly Report on Form 10-Q for the quarterly period ended September 30,  1999).            |
|   |   |             |   |                                                                                                                                                                                                                                                                                                                                               |
|   |   | †10.7— |   | Severance  Agreements by and between Edge Petroleum Corporation and the Officers of the  Company named herein (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).                                                                               |
|   |   |             |   |                                                                                                                                                                                                                                                                                                                                               |
|   |   | †10.8— |   | Form  of Director’s Restricted Stock Award Agreement under the Incentive Plan of  Edge Petroleum Corporation (Incorporated by reference from exhibit 10.12 to  the Company’s Quarterly Report on Form 10-Q for the quarterly period ended  June 30, 2004).                                                                               |

 

55

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|   |   | †10.9—   |   | 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). |
|--------|--------|--------------------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |               |   |                                                                                                                                                                                                                                                             |
|   |   | †10.10—  |   | 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)).                      |
|   |   |               |   |                                                                                                                                                                                                                                                             |
|   |   | †10.11—  |   | Form  of Edge Petroleum Corporation John W. Elias Non-Qualified Stock Option  Agreement (Incorporated by reference from exhibit 4.6 to the Company’s  Registration Statement on Form S-8 filed May 30, 2001 (Registration No.  333-61890)).                 |
|   |   |               |   |                                                                                                                                                                                                                                                             |
|   |   | *†10.12– |   | Summary  of Compensation of Non-Employee Directors.                                                                                                                                                                                                              |
|   |   |               |   |                                                                                                                                                                                                                                                             |
|   |   | *†10.13– |   | Salaries  and Other Compensation of Executive Officers.                                                                                                                                                                                                          |
|   |   |               |   |                                                                                                                                                                                                                                                             |
|   |   | *†10.14– |   | Description  of 2004 Bonus Program for Executive Officers.                                                                                                                                                                                                       |
|   |   |               |   |                                                                                                                                                                                                                                                             |
|   |   | *21.1—        |   | Subsidiaries  of the Company.                                                                                                                                                                                                                                    |
|   |   |               |   |                                                                                                                                                                                                                                                             |
|   |   | *23.1—        |   | Consent  of BDO Seidman, LLP.                                                                                                                                                                                                                                    |
|   |   |               |   |                                                                                                                                                                                                                                                             |
|   |   | *23.2—        |   | Consent  of Ryder Scott Company.                                                                                                                                                                                                                                 |
|   |   |               |   |                                                                                                                                                                                                                                                             |
|   |   | *23.3—        |   | Consent  of W. D. Von Gonten & Co.                                                                                                                                                                                                                           |
|   |   |               |   |                                                                                                                                                                                                                                                             |
|   |   | *31.1—        |   | Certification  by John W. Elias, Chief Executive Officer, pursuant to Section 302 of the  Sarbanes-Oxley Act of 2002.                                                                                                                                            |
|   |   |               |   |                                                                                                                                                                                                                                                             |
|   |   | *31.2—        |   | Certification  by Michael G. Long, Chief Financial Officer, pursuant to Section 302 of the  Sarbanes-Oxley Act of 2002.                                                                                                                                          |
|   |   |               |   |                                                                                                                                                                                                                                                             |
|   |   | *32.1—        |   | Certification  by John W. Elias, Chief Executive Officer, pursuant to 18 USC Section 1350,  as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                |
|   |   |               |   |                                                                                                                                                                                                                                                             |
|   |   | *32.2—        |   | Certification  by Michael G. Long, Chief Financial Officer, pursuant to 18 USC Section 1350,  as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                              |
|   |   |               |   |                                                                                                                                                                                                                                                             |
|   |   | *99.1—        |   | Summary  of Reserve Report of Ryder Scott Company Petroleum Engineers as of December  31, 2004.                                                                                                                                                                  |
|   |   |               |   |                                                                                                                                                                                                                                                             |
|   |   | *99.2—        |   | Summary  of Reserve Report of W. D. Von Gonten & Co. Petroleum Engineers as of  December 31, 2004.                                                                                                                                                           |
|   |   |               |   |                                                                                                                                                                                                                                                             |

 

----

*Filed herewith.

† Denotes management orcompensatory contract, arrangement or agreement.

 

56

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**SIGNATURES**

 

### **Pursuantto the requirements of Section 13 or 15(d) of the Securities Exchange Act of1934, the registrant has duly caused this report to be signed on its behalf bythe undersigned, thereunto duly authorized.**

### ** **

| ** ** | **Edge Petroleum Corporation**               |
|------------|----------------------------------------------|
| ** ** | ** **                                   |
| ** ** | ** **                                   |
|       | /S/ John W.  Elias                           |   |
|       | John W. Elias                                |   |
|       | Chief Executive  Officer and Chairman of the |   |
|       | Board                                        |   |
|            |                                              |  |  |

 

Pursuant to therequirements of the Securities Exchange Act of 1934, this report has beensigned below by the following persons on behalf of the registrant and in thecapacities and on the dates indicated.

 
| /S/ John W.  Elias                                                                                                          |   | Date: March 16, 2005 |   |
|-----------------------------------------------------------------------------------------------------------------------------|--------|----------------------|--------|
| John W. Elias  Chief Executive Officer and Chairman of the Board  (Principal Executive Officer)                             |   |                 |
|                                                                                                                        |   |                 |
| /S/ Michael G.  Long                                                                                                        |   | Date: March 16, 2005 |   |
| Michael G. Long  Senior Vice President and  Chief Financial Officer  (Principal Financial and Principal Accounting Officer) |   |                 |
|                                                                                                                        |   |                 |
| /S/ Thurmon M.  Andress                                                                                                     |   | Date: March 16, 2005 |   |
| Thurmon Andress  Director                                                                                                   |   |                 |
|                                                                                                                        |   |                 |
| /S/ Vincent S.  Andrews                                                                                                     |   | Date: March 16, 2005 |   |
| Vincent Andrews  Director                                                                                                   |   |                 |
|                                                                                                                        |   |                 |
| /S/ Joseph R.  Musolino                                                                                                     |   | Date: March 16, 2005 |   |
| Joseph R.  Musolino  Director                                                                                               |   |                 |
|                                                                                                                        |   |                 |
| /S/ Stanley S.  Raphael                                                                                                     |   | Date: March 16, 2005 |   |
| Stanley S.  Raphael  Director                                                                                               |   |                 |
|                                                                                                                        |   |                 |
| /S/ John  Sfondrini                                                                                                         |   | Date: March 16, 2005 |   |
| John Sfondrini  Director                                                                                                    |   |                 |
|                                                                                                                        |   |                 |
| /S/ Robert W.  Shower                                                                                                       |   | Date: March 16, 2005 |   |
| Robert W. Shower  Director                                                                                                  |   |                 |
|                                                                                                                        |   |                 |
| /S/ David F.  Work                                                                                                          |   | Date: March 16, 2005 |   |
| David F. Work  Director                                                                                                     |   |                 |

 

57

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##### **EDGEPETROLEUM CORPORATION**

 

Index toConsolidated Financial Statements and Supplementary Information

 

**CONSOLIDATED FINANCIALSTATEMENTS**

 
| Audited Financial  Statements:                                                                              |   |
|-------------------------------------------------------------------------------------------------------------|--------|
| Report  of Independent Registered Public Accounting Firm                                                    |   |
|                                                                                                        |   |
| Consolidated Balance Sheets  as of December 31, 2004 and 2003                                               |   |
|                                                                                                        |   |
| Consolidated Statements of  Operations for the Years Ended  December 31, 2004, 2003 and 2002                |   |
|                                                                                                        |   |
| Consolidated  Statements of Comprehensive Income (Loss) for the Years Ended  December 31, 2004, 2003, 2002  |   |
|                                                                                                        |   |
| Consolidated  Statements of Cash Flows for the Years Ended  December 31, 2004, 2003 and 2002                |   |
|                                                                                                        |   |
| Consolidated  Statements of Stockholders’ Equity for the Years Ended  December 31, 2004, 2003 and 2002 |   |
|                                                                                                        |   |
| Notes to  Consolidated Financial Statements                                                                 |   |
|                                                                                                        |   |
| Unaudited Information:                                                                                      |   |
| Supplementary  Information to Consolidated Financial Statements                                             |   |

 

**CONSOLIDATED FINANCIAL STATEMENTSCHEDULES**

 

All schedules for whichprovision is made in the applicable accounting regulations of the Securitiesand Exchange Commission are not required under the related instructions or areinapplicable and therefore have been omitted.

 

F-1

----

 

**Report of Independent RegisteredPublic Accounting Firm**

 

Board of Directors andStockholdersEdge Petroleum Corporation

Houston, Texas

 

We have audited theaccompanying consolidated balance sheets of Edge Petroleum Corporation as ofDecember 31, 2004 and 2003, and the related consolidated statements ofoperations, other comprehensive income (loss), stockholders’ equity, and cashflows for each of the three years in the period ended December 31, 2004.  These financial statements are theresponsibility of the Company’s management. Our responsibility is to express an opinion on these financialstatements based on our audits.

 

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

 

In our opinion, thefinancial statements referred to above present fairly, in all materialrespects, the financial position of Edge Petroleum Corporation at December 31,2004 and 2003, and the results of its operations and its cash flows for each ofthe three years in the period ended December 31, 2004, in conformity withaccounting principles generally accepted in the United States of America.

 

BDO Seidman, LLP

Houston, Texas

 

March 14, 2005

 

F-2

----

 

### **EDGE PETROLEUMCORPORATION**

 

**CONSOLIDATED BALANCE SHEETS**

 
| ** **                                                                                                                                                                                                          | ** ** | **December 31,** | ** **  |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------|-------------|
| ** **                                                                                                                                                                                                          | ** ** | **2004**         | ** **  | **2003** | ** ** |
| **ASSETS**                                                                                                                                                                                                          |       |             |        |   |   |
| ** **                                                                                                                                                                                                          |       |             |        |   |   |
| CURRENT ASSETS:                                                                                                                                                                                                     |       |             |        |   |   |
| Cash and cash  equivalents                                                                                                                                                                                          |       | $                | 2,267,423   |   | $ | 1,327,081 |   |
| Accounts  receivable, trade, net of allowance of $525,248 as of December 31, 2004 and  2003                                                                                                                         |       | 13,715,890       |        | 8,889,734 |   |
| Accounts  receivable, joint interest owners and other, net of allowance of $82,000 as  of December 31, 2004 and 2003                                                                                                |       | 5,911,073        |        | 1,797,877 |   |
| Deferred income  taxes                                                                                                                                                                                              |       | 660,223          |        | 1,138,492 |   |
| Derivative  financial instruments                                                                                                                                                                                   |       | 1,824,790        |        | 120,801 |   |
| Other current  assets                                                                                                                                                                                               |       | 1,445,923        |        | 1,186,987 |   |
| Total current  assets                                                                                                                                                                                               |       | 25,825,322       |        | 14,460,972 |   |
|                                                                                                                                                                                                                |       |             |        |   |   |
| PROPERTY AND  EQUIPMENT, Net – full cost method of accounting for oil and natural gas  properties (including unevaluated costs of $15.5 million and $5.0 million at  December 31, 2004 and 2003, respectively) |       | 165,840,345      |        | 97,980,757 |   |
|                                                                                                                                                                                                                |       |             |        |   |   |
| OTHER ASSETS                                                                                                                                                                                                        |       | 284,280          |        | — |   |
|                                                                                                                                                                                                                |       |             |        |   |   |
| DEFERRED INCOME  TAXES                                                                                                                                                                                              |       | —           |        | 5,570,137 |   |
|                                                                                                                                                                                                                |       |             |        |   |   |
| TOTAL ASSETS                                                                                                                                                                                                        |       | $                | 191,949,947 |   | $ | 118,011,866 |   |
|                                                                                                                                                                                                                |       |             |        |   |   |
| **LIABILITIES  AND STOCKHOLDERS’ EQUITY**                                                                                                                                                                      |       |             |        |   |   |
| ** **                                                                                                                                                                                                          |       |             |        |   |   |
| CURRENT  LIABILITIES:                                                                                                                                                                                               |       |             |        |   |   |
| Accounts  payable, trade                                                                                                                                                                                            |       | $                | 3,141,235   |   | $ | 1,732,935 |   |
| Accrued  liabilities                                                                                                                                                                                                |       | 13,065,487       |        | 11,456,036 |   |
| Derivative  financial instruments                                                                                                                                                                                   |       | 468,308          |        | — |   |
| Asset retirement  obligation – current portion                                                                                                                                                                 |       | 193,647          |        | 323,513 |   |
|                                                                                                                                                                                                                |       |             |        |   |   |
| Total current  liabilities                                                                                                                                                                                          |       | 16,868,677       |        | 13,512,484 |   |
|                                                                                                                                                                                                                |       |             |        |   |   |
| ASSET RETIREMENT  OBLIGATION – long-term portion                                                                                                                                                               |       | 1,995,441        |        | 1,488,482 |   |
|                                                                                                                                                                                                                |       |             |        |   |   |
| DEFERED TAX  LIABILITY                                                                                                                                                                                              |       | 2,618,934        |        | — |   |
|                                                                                                                                                                                                                |       |             |        |   |   |
| LONG-TERM DEBT                                                                                                                                                                                                      |       | 20,000,000       |        | 21,000,000 |   |
| Total  liabilities                                                                                                                                                                                                  |       | 41,483,052       |        | 36,000,966 |   |
|                                                                                                                                                                                                                |       |             |        |   |   |
| COMMITMENTS AND  CONTINGENCIES (Note 12)                                                                                                                                                                            |       |             |        |   |   |
|                                                                                                                                                                                                                |       |             |        |   |   |
| 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; 16,535,901 and 12,581,032  shares issued and outstanding at December 31, 2004 and 2003, respectively                                                  |       | 165,359          |        | 125,810 |   |
|                                                                                                                                                                                                                |       |             |        |   |   |
| Additional  paid-in capital                                                                                                                                                                                         |       | 126,957,059      |        | 75,282,007 |   |
| Retained  earnings                                                                                                                                                                                                  |       | 22,095,807       |        | 6,966,557 |   |
| Accumulated  other comprehensive income (loss)                                                                                                                                                                      |       | 1,248,670        |        | (363,474 | ) |
| Total  stockholders’ equity                                                                                                                                                                                    |       | 150,466,895      |        | 82,010,900 |   |
| TOTAL  LIABILITIES AND STOCKHOLDERS’ EQUITY                                                                                                                                                                    |       | $                | 191,949,947 |   | $ | 118,011,866 |   |

 

See accompanyingnotes to the consolidated financial statements.

 

F-3

----

 

### **EDGE**PETROLEUM CORPORATION

 

**CONSOLIDATED STATEMENTS OFOPERATIONS**

 
| ** **                                                                        | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                        | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| OIL AND NATURAL  GAS REVENUE:                                                     |       |                        |       |   |   |   |   |
| Oil and natural  gas sales                                                        |       | $                           | 66,965,411 |   | $ | 38,381,597 |   | $ | 21,238,244 |   |
| Loss on hedging  and derivatives                                                  |       | (2,460,063                  | )          | (4,455,590 | ) | (326,950 | ) |
| Total revenue                                                                     |       | 64,505,348                  |       | 33,926,007 |   | 20,911,294 |   |
|                                                                              |       |                        |       |   |   |   |   |
| OPERATING  EXPENSES:                                                              |       |                        |       |   |   |   |   |
| Oil and natural  gas operating expenses including production and ad valorem taxes |       | 9,308,770                   |       | 5,115,794 |   | 3,831,590 |   |
| Depletion,  depreciation, amortization and accretion                              |       | 21,927,874                  |       | 13,577,279 |   | 10,426,667 |   |
| General and  administrative expenses:                                             |       |                        |       |   |   |   |   |
| Deferred  compensation expense – repriced options                            |       | 1,135,628                   |       | 1,219,349 |   | 3,385 |   |
| Deferred  compensation expense – restricted stock                            |       | 498,372                     |       | 372,151 |   | 399,249 |   |
| Other general  and administrative                                                 |       | 7,812,970                   |       | 5,540,140 |   | 4,826,793 |   |
| Total operating  expenses                                                         |       | 40,683,614                  |       | 25,824,713 |   | 19,487,684 |   |
| OPERATING INCOME                                                                  |       | 23,821,734                  |       | 8,101,294 |   | 1,423,610 |   |
|                                                                              |       |                        |       |   |   |   |   |
| OTHER INCOME  (EXPENSE):                                                          |       |                        |       |   |   |   |   |
| Interest  expense, net of amounts capitalized                                     |       | (331,399                    | )          | (678,805 | ) | (143,280 | ) |
| Amortization of  deferred loan costs                                              |       | (142,135                    | )          | — |   | (84,479 | ) |
| Interest income                                                                   |       | 36,075                      |       | 16,518 |   | 26,954 |   |
|                                                                              |       |                        |       |   |   |   |   |
| INCOME BEFORE  INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE            |       | 23,384,275                  |       | 7,439,007 |   | 1,222,805 |   |
|                                                                              |       |                        |       |   |   |   |   |
| INCOME TAX  EXPENSE                                                               |       | (8,255,025                  | )          | (2,731,132 | ) | (473,060 | ) |
|                                                                              |       |                        |       |   |   |   |   |
| INCOME BEFORE  CUMULATIVE EFFECT OF ACCOUNTING CHANGE                             |       | 15,129,250                  |       | 4,707,875 |   | 749,745 |   |
|                                                                              |       |                        |       |   |   |   |   |
| CUMULATIVE  EFFECT OF ACCOUNTING CHANGE                                           |       | —                      |       | (357,825 | ) | — |   |
|                                                                              |       |                        |       |   |   |   |   |
| NET INCOME                                                                        |       | $                           | 15,129,250 |   | $ | 4,350,050 |   | $ | 749,745 |   |
|                                                                              |       |                        |       |   |   |   |   |
| BASIC EARNINGS  PER SHARE:                                                        |       |                        |       |   |   |   |   |
|                                                                              |       |                        |       |   |   |   |   |
| Income before  cumulative effect of accounting change                             |       | $                           | 1.16       |   | $ | 0.48 |   | $ | 0.08 |   |
|                                                                              |       |                        |       |   |   |   |   |
| Cumulative  effect of accounting change                                           |       | —                      |       | (0.03 | ) | — |   |
|                                                                              |       |                        |       |   |   |   |   |
| Basic earnings  per share                                                         |       | $                           | 1.16       |   | $ | 0.45 |   | $ | 0.08 |   |
|                                                                              |       |                        |       |   |   |   |   |
| DILUTED EARNINGS  PER SHARE:                                                      |       |                        |       |   |   |   |   |
|                                                                              |       |                        |       |   |   |   |   |
| Income before  cumulative effect of accounting change                             |       | $                           | 1.11       |   | $ | 0.47 |   | $ | 0.08 |   |
|                                                                              |       |                        |       |   |   |   |   |
| Cumulative  effect of accounting change                                           |       | —                      |       | (0.03 | ) | — |   |
|                                                                              |       |                        |       |   |   |   |   |
| Diluted earnings  per share                                                       |       | $                           | 1.11       |   | $ | 0.44 |   | $ | 0.08 |   |
|                                                                              |       |                        |       |   |   |   |   |
| BASIC WEIGHTED  AVERAGE NUMBER OF COMMON SHARES OUTSTANDING                       |       | 13,029,075                  |       | 9,726,140 |   | 9,384,097 |   |
|                                                                              |       |                        |       |   |   |   |   |
| DILUTED WEIGHTED  AVERAGE NUMBER OF COMMON SHARES OUTSTANDING                     |       | 13,648,261                  |       | 9,987,551 |   | 9,605,571 |   |

 

See accompanyingnotes to the consolidated financial statements**.**

 

F-4

----

 

### **EDGE PETROLEUM**CORPORATION

 

**CONSOLIDATED STATEMENTS OF OTHERCOMPREHENSIVE INCOME (LOSS)**

 
| ** **                                                                  | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                  | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| NET INCOME                                                                  |       | $                           | 15,129,250 |   | $ | 4,350,050 |   | $ | 749,745 |   |
|                                                                        |       |                        |       |   |   |   |   |
| OTHER  COMPREHENSIVE INCOME (LOSS), net of tax:                             |       |                        |       |   |   |   |   |
| Change in fair  value of outstanding hedging and derivative instruments (1) |       | 1,248,670                   |       | (363,474 | ) | (840,996 | ) |
| Reclassification  of hedging and derivative losses (2)                      |       | 363,474                     |       | 840,996 |   | — |   |
| Other  comprehensive income (loss)                                          |       | 1,612,144                   |       | 477,522 |   | (840,996 | ) |
|                                                                        |       |                        |       |   |   |   |   |
| COMPREHENSIVE  INCOME (LOSS)                                                |       | $                           | 16,741,394 |   | $ | 4,827,572 |   | $ | (91,251 | ) |

 

----

| (1) net of  income tax (expense) benefit of |   | $ | 672,360 |   | $ | (201,975 | )      | $ | (452,844 | )      |
|---------------------------------------------|--------|---|---------|--------|---|----------|--------|---|----------|--------|
| (2) net of income  tax (expense) benefit of |   | $ | 201,975 |   | $ | 452,844  |   | $ | —   |   |

 

See accompanyingnotes to the consolidated financial statements**.**

 

F-5

----

 

 

### **EDGE PETROLEUM**CORPORATION

**CONSOLIDATED STATEMENTS OF CASHFLOWS**

 
| ** **                                                                         | ** ** | **Year Ended December 31,** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                         | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| CASH FLOWS FROM  OPERATING ACTIVITIES:                                             |       |                        |       |   |   |   |   |
|                                                                               |       |                        |       |   |   |   |   |
| Net income                                                                         |       | $                           | 15,129,250 |   | $ | 4,350,050 |   | $ | 749,745 |   |
| Adjustments to  reconcile net income to net cash provided by operating activities: |       |                        |       |   |   |   |   |
| Cumulative  effect of accounting change                                            |       | —                      |       | 357,825 |   | — |   |
| Unrealized loss  on the fair value of derivatives                                  |       | 564,548                     |       | — |   | — |   |
| Depletion,  depreciation, amortization and accretion                               |       | 21,927,874                  |       | 13,577,279 |   | 10,426,667 |   |
| Amortization of  deferred loan costs                                               |       | 142,135                     |       | — |   | 84,479 |   |
| Deferred tax  provision                                                            |       | 8,255,025                   |       | 2,731,132 |   | 473,060 |   |
| Non-cash  compensation expense                                                     |       | 1,634,000                   |       | 1,591,500 |   | 402,634 |   |
| Changes in  operating assets and liabilities:                                      |       |                        |       |   |   |   |   |
| (Increase)  decrease in accounts receivable, trade                                 |       | (4,139,906                  | )          | (3,137,319 | ) | 691,989 |   |
| (Increase)  decrease in accounts receivable, joint interest owners                 |       | (4,113,196                  | )          | (1,187,958 | ) | 113,555 |   |
| (Increase)  decrease in other assets                                               |       | (258,936                    | )          | (429,403 | ) | 141,945 |   |
| Increase  (decrease) in accounts payable, trade                                    |       | 1,408,300                   |       | (1,767,685 | ) | 121,521 |   |
| Increase  (decrease) in accrued interest payable                                   |       | —                      |       | (127,698 | ) | 127,698 |   |
| Increase  (decrease) in accrued liabilities                                        |       | 1,721,248                   |       | 7,940,421 |   | (2,925,712 | ) |
| Net cash  provided by operating activities                                         |       | 42,270,342                  |       | 23,898,144 |   | 10,407,581 |   |
|                                                                               |       |                        |       |   |   |   |   |
| CASH FLOWS FROM  INVESTING ACTIVITIES:                                             |       |                        |       |   |   |   |   |
| Capital  expenditures                                                              |       | (89,470,369                 | )          | (33,560,102 | ) | (19,609,639 | ) |
| Proceeds from  the sale of oil and natural gas properties                          |       | 60,000                      |       | 330,096 |   | 354,294 |   |
| Cash acquired in  merger with Miller Exploration Company, net of acquisition costs |       | —                      |       | 5,159,806 |   | — |   |
| Net cash used in  investing activities                                             |       | (89,410,369                 | )          | (28,070,200 | ) | (19,255,345 | ) |
|                                                                               |       |                        |       |   |   |   |   |
| CASH FLOWS FROM  FINANCING ACTIVITIES:                                             |       |                        |       |   |   |   |   |
| Borrowings from  long-term debt                                                    |       | 27,000,000                  |       | 10,700,000 |   | 11,000,000 |   |
| Payments on  long-term debt                                                        |       | (28,000,000                 | )          | (10,200,000 | ) | (500,000 | ) |
| Net proceeds  from issuance of common stock                                        |       | 49,506,784                  |       | 2,430,961 |   | 122,653 |   |
| Loan costs                                                                         |       | (426,415                    | )          | — |   | — |   |
| Net cash  provided by financing activities                                         |       | 48,080,369                  |       | 2,930,961 |   | 10,622,653 |   |
|                                                                               |       |                        |       |   |   |   |   |
| NET INCREASE  (DECREASE) IN CASH AND CASH EQUIVALENTS                              |       | 940,342                     |       | (1,241,095 | ) | 1,774,889 |   |
| CASH AND CASH  EQUIVALENTS, BEGINNING OF YEAR                                      |       | 1,327,081                   |       | 2,568,176 |   | 793,287 |   |
| CASH AND CASH  EQUIVALENTS, END OF YEAR                                            |       | $                           | 2,267,423  |   | $ | 1,327,081 |   | $ | 2,568,176 |   |

 

See accompanyingnotes to the consolidated financial statements.

 

F-6

----

 

### **EDGE PETROLEUM**CORPORATION

 

### **CONSOLIDATEDSTATEMENTS OF STOCKHOLDERS’ EQUITY**

 
| ** **                                                           | ** ** | **Common Stock** | ** ** | **Additional** | ** ** | **Retained  Earnings** | ** ** | **Accumulated  Other  Comprehensive** | ** ** | **Total  Stockholders’** | ** ** |
|----------------------------------------------------------------------|------------|------------------|------------|----------------|------------|------------------------|------------|---------------------------------------|------------|-------------------------------|------------|
| ** **                                                           | ** ** | **Shares**       | ** ** | **Amount**     | ** ** | **Paid-in Capital**    | ** ** | **(Deficit)**                         | ** ** | **Income (Loss)**             | ** ** | **Equity** | ** ** |
| **BALANCE,  DECEMBER 31, 2001**                                      |       | 9,305,079        |       | $              | 93,051     |                   | $          | 56,139,451                            |       | $                             | 1,866,762  |   | $ | — |   | $ | 58,099,264 |   |
| Issuance of  common stock                                            |       | 111,175          |       | 1,112          |       | 121,541                |       | —                                |       | —                        |       | 122,653 |   |
| Deferred  compensation expense – restricted stock               |       | —           |       | —         |       | 399,249                |       | —                                |       | —                        |       | 399,249 |   |
| Deferred  compensation expense – repriced options               |       | —           |       | —         |       | 3,385                  |       | —                                |       | —                        |       | 3,385 |   |
| Change in  valuation of hedging instruments                          |       | —           |       | —         |       | —                 |       | —                                |       | (840,996                      | )          | (840,996 | ) |
| Net income                                                           |       | —           |       | —         |       | —                 |       | 749,745                               |       | —                        |       | 749,745 |   |
| **BALANCE,  DECEMBER 31, 2002**                                      |       | 9,416,254        |       | 94,163         |       | 56,663,626             |       | 2,616,507                             |       | (840,996                      | )          | 58,533,300 |   |
| Issuance of  common stock                                            |       | 3,164,778        |       | 31,647         |       | 16,889,740             |       | —                                |       | —                        |       | 16,921,387 |   |
| Deferred  compensation expense – restricted stock               |       | —           |       | —         |       | 372,151                |       | —                                |       | —                        |       | 372,151 |   |
| Deferred  compensation expense – repriced options               |       | —           |       | —         |       | 1,219,349              |       | —                                |       | —                        |       | 1,219,349 |   |
| Tax benefit  associated with exercise of non-qualified stock options |       | —           |       | —         |       | 137,141                |       | —                                |       | —                        |       | 137,141 |   |
| Reclassification  of hedging losses                                  |       | —           |       | —         |       | —                 |       | —                                |       | 840,996                       |       | 840,996 |   |
| Change in  valuation of hedging instruments                          |       | —           |       | —         |       | —                 |       | —                                |       | (363,474                      | )          | (363,474 | ) |
|                                                                 |       |             |       |           |       |                   |       |                                  |       |                          |       |   |   |
| Net income                                                           |       | —           |       | —         |       | —                 |       | 4,350,050                             |       | —                        |       | 4,350,050 |   |
| **BALANCE,  DECEMBER 31, 2003**                                      |       | 12,581,032       |       | 125,810        |       | 75,282,007             |       | 6,966,557                             |       | (363,474                      | )          | 82,010,900 |   |
| Issuance of  common stock                                            |       | 3,954,869        |       | 39,549         |       | 49,579,032             |       | —                                |       | —                        |       | 49,618,581 |   |
| Deferred  compensation expense – restricted stock               |       | —           |       | —         |       | 498,372                |       | —                                |       | —                        |       | 498,372 |   |
| Deferred  compensation expense – repriced options               |       | —           |       | —         |       | 1,135,628              |       | —                                |       | —                        |       | 1,135,628 |   |
| Tax benefit  associated with exercise of non-qualified stock options |       | —           |       | —         |       | 462,020                |       | —                                |       | —                        |       | 462,020 |   |
| Reclassification  of hedging losses                                  |       | —           |       | —         |       | —                 |       | —                                |       | 363,474                       |       | 363,474 |   |
| Change in  valuation of hedging instruments                          |       | —           |       | —         |       | —                 |       | —                                |       | 1,248,670                     |       | 1,248,670 |   |
|                                                                 |       |             |       |           |       |                   |       |                                  |       |                          |       |   |   |
| Net income                                                           |       | —           |       | —         |       | —                 |       | 15,129,250                            |       | —                        |       | 15,129,250 |   |
| **BALANCE,  DECEMBER 31, 2004**                                      |       | 16,535,901       |       | $              | 165,359    |                   | $          | 126,957,059                           |       | $                             | 22,095,807 |   | $ | 1,248,670 |   | $ | 150,466,895 |   |

 

See accompanyingnotes to the consolidated financial statements**.**

 

F-7

----

 

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

**1.     ORGANIZATION AND NATURE OF OPERATIONS**

 

***General-***Edge Petroleum Corporation(the “Company”) was organized as a Delawarecorporation in August 1996 in connection with its initial public offering andthe related combination of certain entities that held interests in Edge JointVenture II (the “Joint Venture”) and certain other oil and natural gasproperties; herein referred to as the “Combination”.  In a series of transactions the Companyissued an aggregate of 4,701,361 shares of common stock and received inexchange 100 percent of the ownership interests in the Joint Venture andcertain other oil and natural gas properties. In March 1997, and contemporaneously with the Combination, the Companycompleted the initial public offering of 2,760,000 shares of its common stock(the “Offering”). In December 2003, the Company completed a merger with MillerExploration Company (“Miller”) in a stock for stock transaction, in which theCompany issued 2.6 million shares of common stock to the shareholders ofMiller.

 

***Natureof Operations -*****The Company isan independent energy company engaged in the exploration, development,acquisition and production of oil and natural gas. The Company’s resources andassets are managed and its results are reported as one operating segment. TheCompany conducts its operations primarily along the onshore United States GulfCoast, with its primary emphasis in south Texas, Mississippi, Louisiana andSoutheast New Mexico. In its exploration efforts the Company emphasizes anintegrated geologic interpretation method incorporating 3-D seismic technologyand advanced visualization and data analysis techniques utilizingstate-of-the-art computer hardware and software.

 

**2.****              SUMMARY OFSIGNIFICANT ACCOUNTING POLICIES**

 

***Principlesof Consolidation -*** The consolidated financial statementsinclude the accounts of all majority owned subsidiaries of the Company,including Edge Petroleum Operating Company Inc., Edge Petroleum ExplorationCompany, Miller Oil Corporation, and Miller Exploration Company, which are 100percent owned subsidiaries of the Company. All intercompany balances and transactions have been eliminated inconsolidation.

 

***Changes in Accounting Principles******-*** None.

 

***Cashand Cash Equivalents -*** The Company considers all highlyliquid investments with original maturities of three months or less to be cashequivalents.

 

***FinancialInstruments -*** The Company’s financial instruments consistof cash, receivables, payables, long-term debt and oil and natural gas commodityhedges.  The carrying amount of cash,receivables and payables approximates fair value because of the short-termnature of these items.  The carryingamount of long-term debt as of December 31, 2004 and 2003 approximates fairvalue because the interest rates are variable and reflective of market rates.Our hedging instruments are reflected at fair value based on quotes obtainedfrom our counterparties.

 

***RevenueRecognition -*** The Company recognizes oil and natural gasrevenue from its interests in producing wells as oil and natural gas isproduced and sold from those wells.  Oiland natural gas sold by the Company is not significantly different from theCompany’s share of production.

 

***Allowancefor Doubtful Accounts******-*** The Companyroutinely assesses the recoverability of all material trade and otherreceivables to determine their collectibility. Many of Edge’s receivables arefrom joint interest owners on properties of which the Company is the operator.Thus, Edge may have the ability to withhold future revenue disbursements torecover any non-payment of joint interest billings.  Generally, the Company’s crude oil andnatural gas receivables are collected within two months.  The Company accrues a reserve on a receivablewhen, based on the judgment of management, it is probable that a receivablewill not be collected and the amount of any reserve may be reasonablyestimated. As of December 31, 2004 and 2003, the Company had an allowance fordoubtful accounts of $525,248 related to trade receivables and $82,000 relatedto joint interest receivables (see Note 3).

 

F-8

----

 

***Inventories-***Inventoriesconsist principally of tubular goods and production equipment, stated at thelower of weighted-average cost or market.

 

***OtherProperty, Plant & Equipment -***Depreciation of otheroffice furniture and equipment and computer hardware and software is providedusing the straight-line method based on estimated useful lives ranging fromthree to seven years.

 

***Oiland Natural Gas Properties -*** Investments in oil and natural gasproperties are accounted for using the full cost method of accounting.  The accounting for our business is subject tospecial accounting rules that are unique to the oil and gas industry and thereare two allowable methods of accounting for oil and gas businessactivities:  the successful-effortsmethod and the full-cost method.  Thereare several significant differences between these methods. Among thesedifferences is that, under the successful-efforts method, costs such asgeological and geophysical (“G&G”), exploratory dry holes and delay rentalsare expensed as incurred whereas under the full-cost method these types ofcharges are capitalized to their respective full-cost pool.  In the measurement of impairment of oil andgas properties, the successful-efforts method of accounting follows theguidance provided in Statement of Financial Accounting Standards (“SFAS”) No.144, “*Accounting for the Impairment orDisposal of Long-Lived Assets*,” where the first measurement forimpairment is to compare the net book value of the related asset to itsundiscounted future cash flows using commodity prices consistent withmanagement expectations.  The full-costmethod follows guidance provided in Securities and Exchange Commission (“SEC”)Regulation S-X Rule 4-10, where impairment is determined by comparing the netbook value (full-cost pool) to the future net cash flows discounted at 10%using commodity prices in effect at the end of the reporting period.

 

In accordance with thefull-cost method of accounting, all costs associated with the exploration,development and acquisition of oil and natural gas properties, includingsalaries, benefits and other internal costs directly attributable to theseactivities are capitalized within a cost center. The Company’s oil and naturalgas properties are located within the United States of America, whichconstitutes one cost center. The Company capitalized $2.2 million, $1.7million, and $1.5 million of general and administrative costs in 2004, 2003 and2002, respectively. The Company also capitalizes a portion of interest expenseon borrowed funds related to unproved oil and gas properties. The Companycapitalized approximately $701,700, $244,500, and $623,400 of interest costs in2004, 2003 and 2002, respectively.

 

Oil and natural gasproperties are amortized using the unit-of-production method using estimates ofproved reserve quantities.  Investmentsin unproved properties are not amortized until proved reserves associated withthe prospects can be determined or until impairment occurs. Unproved oil andnatural gas properties consist of the cost of unevaluated leaseholds, cost ofseismic data, exploratory and developmental wells in progress, and secondaryrecovery projects before the assignment of proved reserves. Oil and natural gasproperties include costs of $15.5 million and $5.0 million at December 31, 2004and 2003, respectively, related to unproved property, which were excluded fromcapitalized costs being amortized. Unproved properties are evaluated quarterly,and as needed, for impairment on a property-by-property basis. Factorsconsidered by management in its impairment assessment include drilling resultsby the Company and other operators, the terms of oil and natural gas leases notheld by production, production response to secondary recovery activities andavailable funds for exploration and development. If the results of anassessment indicate that an unproved property is impaired, the amount ofimpairment is added to the proved oil and natural gas property costs to beamortized. In September 2004, the Securities and Exchange Commission (“SEC”)issued SEC Staff Accounting Bulletin (“SAB”) No. 106, *“Interaction of Statement 143 and the Full CostRules,”* which the Company adopted in the fourth quarter of 2004 withno impact on the Company’s financial statements. In accordance with SAB No. 106*,*the amortizable base used to calculateunit-of-production depletion includes estimated future development anddismantlement costs, and restoration and abandonment costs, net of estimatedsalvage values. The depletion rates per Mcfe for the years ended December 31,2004, 2003 and 2002 were $1.78, $1.59, and $1.39, respectively.

 

In addition, thecapitalized costs of oil and natural gas properties are subject to a “ceilingtest,” whereby to the extent that such capitalized costs subject toamortization in the full cost pool (net of depletion, depreciation andamortization, asset retirement obligations and related deferred taxes) exceedthe present value (using 10% discount rate) of estimated future net after-taxcash flows from proved oil and natural gas reserves, such excess costs arecharged to operations.  Once incurred, animpairment of oil and natural gas properties is not reversible at a later date.In accordance with SAB No. 103, “*Update ofCodification of Staff Accounting Bulletins*,” derivative instrumentsqualifying as cash flow hedges are included in the computation of limitation oncapitalized costs. The period-end price was between the cap and floorestablished by the Company’s hedge contracts at December 31, 2004 and thus

 

F-9

----

 

noimpact was included in the calculation. Impairment of oil and natural gasproperties is assessed on a quarterly basis in conjunction with the Company’squarterly filings with the SEC.  Theperiod-end price was within the collar established by the Company’s hedges atDecember 31, 2004 and thus did not affect prices used in this calculation.  No adjustment related to the ceiling test wasrequired during the years ended December 31, 2004, 2003, or 2002.

 

Sales of proved andunproved properties are accounted for as adjustments of capitalized costs withno gain or loss recognized, unless such adjustments would significantly alterthe relationship between capitalized costs and proved reserves.

 

In March 2004, theEmerging Issues Task Force (“EITF”) reached a consensus that mineral rights, asdefined in EITF Issue No. 04-2, *“WhetherMineral Rights Are Tangible or Intangible Assets,”* are tangibleassets and that they should be removed as examples of intangible assets in SFASNos. 141, *“Business Combinations,”*and SFAS No. 142, *“Goodwill and OtherIntangible Assets.”* The Financial Accounting Standards Board (“FASB”)has recently ratified this consensus and directed the FASB staff to amend SFASNos. 141 and 142 through the issuance of FASB Staff Positions (“FSP”) Nos. FAS141-1 and FAS 142-1, *“Interaction of FASBStatements No. 141, Business Combinations, and No. 142,****Goodwill and Other Intangible Assets, andEITF Issue No. 04-2, “Whether Mineral Rights Are Tangible or Intangible Assets.”* In addition, FSP FAS 142-2, *“**Application of FASB Statement No. 142, Goodwill andOther Intangible Assets, to Oil- and Gas-Producing Entities”*confirms that SFAS No. 142 does not change the balance sheet classification ordisclosures of mineral rights of oil and gas producing enterprises.Historically, we have included the costs of such mineral rights as tangibleassets, which is consistent with the EITF’s consensus. As such, EITF 04-2 andthe related FSPs have not affected our consolidated financial statements.

 

***Asset Retirement Obligations –***TheCompany accounts for asset retirement obligations under the provisions of SFASNo. 143, “*Accounting for Asset RetirementObligations,”*which provides for an asset and liability approach toaccounting for Asset Retirement Obligations (“ARO”). Under this method, whenlegal obligations for dismantlement and abandonment costs, excluding salvagevalues, are incurred, a liability is recorded at fair value and the carryingamount of the related oil and gas properties is increased. Accretion of theliability is recognized each period using the interest method of allocation andthe capitalized cost is depleted over the useful life of the related asset. TheCompany adopted this policy effective January 1, 2003, using a cumulativeeffect approach to recognize transition amounts for asset retirementobligations, asset retirement costs and accumulated accretion and depletion.The cumulative effect of the adoption of SFAS No. 143 and the change inaccounting principle was a charge to net income during the first quarter of2003 of $357,825, net of taxes of $192,675. (See Note 7)

 

***IncomeTaxes******-*** The Company accounts for income taxes under theprovisions of SFAS No. 109, “*Accounting forIncome Taxes*,” which provides for an asset and liability approach toaccounting for income taxes.  Under thisapproach, deferred tax assets and liabilities are recognized based on anticipatedfuture tax consequences, using currently enacted tax laws, attributable todifferences between financial statement carrying amounts of assets andliabilities and their respective tax bases (see Note 14).

 

***Stock-BasedCompensation -*** The Company accounts for stock compensationplans under the intrinsic value method of Accounting Principles Board (“APB”)Opinion No. 25, “*Accounting for Stock Issuedto Employees*.”  Nocompensation expense is recognized for stock options that had an exercise priceequal to the market value of the underlying common stock on the date ofgrant.  As allowed by SFAS No. 123, “*Accounting for Stock Based Compensation*,”the Company has continued to apply APB Opinion No. 25 for purposes ofdetermining net income, but SFAS No. 123, as amended, requires prominentdisclosures in both annual and interim financial statements about the method ofaccounting for stock-based compensation and the effect of the method used onreported results. SFAS No. 123 was revised in December 2004 to eliminate theuse of APB Opinion No. 25 after the second quarter of 2005 (see Recently IssuedAccounting Pronouncements below).

 

Had compensation expensefor stock-based compensation been determined based on the fair value at thedate of grant, our net income and earnings per share would have been asfollows:

 

F-10

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| ** **                                                                                                                           | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                                                           | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| Net income as  reported                                                                                                              |       | $                           | 15,129,250 |   | $ | 4,350,050 |   | $ | 749,745 |   |
| Add:                                                                                                                                 |       |                        |       |   |   |   |   |
| Stock based  employee compensation expense included in reported net income, net of related  income tax                               |       | 1,062,100                   |       | 771,681 |   | 2,075 |   |
| Deduct:                                                                                                                              |       |                        |       |   |   |   |   |
| Total stock  based employee compensation expense determined under fair value based method  for all awards, net of related income tax |       | (501,907                    | )          | (260,850 | ) | (261,927 | ) |
|                                                                                                                                 |       |                        |       |   |   |   |   |
| Pro forma net  income                                                                                                                |       | $                           | 15,689,443 |   | $ | 4,860,881 |   | $ | 489,893 |   |
|                                                                                                                                 |       |                        |       |   |   |   |   |
| Earnings Per  Share                                                                                                                  |       |                        |       |   |   |   |   |
| Basic – as  reported                                                                                                            |       | $                           | 1.16       |   | $ | 0.45 |   | $ | 0.08 |   |
| Basic – pro  forma                                                                                                              |       | 1.20                        |       | 0.50 |   | 0.05 |   |
|                                                                                                                                 |       |                        |       |   |   |   |   |
| Diluted – as  reported                                                                                                          |       | $                           | 1.11       |   | $ | 0.44 |   | $ | 0.08 |   |
| Diluted – pro  forma                                                                                                            |       | 1.15                        |       | 0.49 |   | 0.05 |   |

 

The weighted-average fairvalue of each option granted during 2004, 2003 and 2002 was $11.03, $3.24, and$4.19, respectively.  The fair value ofeach option grant is estimated on the date of grant using the Black-Scholesoption-pricing model with the following weighted-average assumptions: expectedstock price volatility of 72%, 73%, and 77% in 2004, 2003 and 2002,respectively; risk free interest rate of 3.76%, 3.76%, and 3.82% in 2004, 2003and 2002, respectively; average expected option lives of ten years for 2004 andeight years in 2003 and 2002, respectively; and over the vesting period of suchoptions a forfeiture rate of 0% for 2004 and 10% for 2003 and 2002.

 

The Company is alsosubject to reporting requirements of FASB Interpretation No. (“FIN”) 44, “*Accounting for Certain**Transactions involvingStock Compensation,”* that requires variable accounting for re-pricedstock options. A non-cash charge to deferred compensation expense is recordedif the market price of the Company’s common stock at the end of a reportingperiod is greater than the exercise price of certain re-priced stockoptions.  After the first such adjustmentis made, each subsequent period is adjusted upward or downward to the extentthat the market price exceeds the exercise price of the options.  The charge is related to non-qualified stockoptions granted to employees and directors in prior years and re-priced in May1999, as well as certain options newly issued in conjunction with the repricing(see Note 16). A pre-tax charge of $1.1 million, $1.2 million and $3,385 wasrequired for the years ended December 31, 2004, 2003 and 2002, respectively.

 

***EarningsPer Share -*** The Company accounts for its earnings pershare in accordance with SFAS No. 128, “*Earningsper Share*,” which requires the presentation of “basic” and “diluted”EPS on the face of the income statement. Basic earnings per common shareamounts are calculated using the average number of common shares outstandingduring each period.  Diluted earnings pershare assumes the exercise of all stock options and warrants having exerciseprices less than the average market price of the common stock using thetreasury stock method (see Note 16).

 

***Derivativesand Hedging Activities -*****TheCompany adopted SFAS No. 133, “*Accountingfor Derivative Instruments and Hedging Activities*” effective January1, 2001.  The statement, as amended by SFAS No. 137 *“Accountingfor Derivative Instruments and Hedging Activities - Deferral of the EffectiveDate of FASB Statement No. 133 - an Amendment of FASB Statement No. 133”*andSFAS No. 138, *“Accounting for CertainDerivative Instruments and Certain Hedging Activities - an Amendment of FASBStatement No. 133”,*requires that all derivatives berecognized as either assets or liabilities and measured at fair value, andchanges in the fair value of derivatives be reported in current earnings,unless the derivative qualifies for special hedge accounting treatment. If thederivative is designated as a cash flow hedge and the intended use of thederivative is to hedge the exposure to variability in expected future cashflows then the changes in the fair value of the derivative instrument willgenerally be reported in Other Comprehensive Income (“OCI”).  The gains and losses on the derivativeinstrument that are

 

F-11

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reported in OCI will be reclassified to earnings in the period in whichearnings are impacted by the hedged item (see Note 9).  Upon adoption of SFAS No. 133, the Companyrecorded a transition adjustment of approximately $(1.1) million in accumulatedother comprehensive income to record the fair value of the natural gas hedgesthat were outstanding at that date. If hedge accounting is discontinued becauseit is probable that a forecasted transaction will not occur, the derivativewill continue to be carried on the balance sheet at its fair value and gainsand losses that were accumulated in other comprehensive income will berecognized in earnings immediately.

 

***ComprehensiveIncome -***The Company follows the provisions of SFAS No.130, “*Reporting Comprehensive Income*”.SFAS No. 130 establishes standards for reporting and presentation ofcomprehensive income and its components. SFAS No. 130 requires that all itemsthat are required to be recognized under accounting standards as components ofcomprehensive income be reported in a financial statement that is displayedwith the same prominence as other financial statements. In accordance with theprovisions of SFAS No. 130, the Company has presented the components ofcomprehensive income below the total for net income on the face of theconsolidated statements of operations. For the years ended December 31, 2004,2003 and 2002, the only component of other comprehensive income have beenchanges in fair value of hedging instruments and reclassifications of hedginggains and losses.

 

***Useof Estimates -*** The preparation of financial statements inconformity with accounting principles generally accepted in the United Statesof America requires management to make estimates and assumptions that affectthe reported amounts of assets and liabilities and disclosure of contingentassets and liabilities as of the date of the financial statements and thereported amounts of revenues and expenses during the reporting periods.  Actual results could differ from theseestimates.

 

Significant estimatesinclude volumes of oil and gas reserves used in calculating depletion of provedoil and natural gas properties, future net revenues and abandonmentobligations, impairment of undeveloped properties, future income taxes andrelated assets/liabilities, bad debts, derivatives, contingencies andlitigation. Oil and natural gas reserve estimates, which are the basis forunit-of-production depletion and the ceiling test, have numerous inherentuncertainties. The accuracy of any reserve estimate is a function of thequality of available data and of engineering and geological interpretation andjudgment.  Results of drilling, testing,and production subsequent to the date of the estimate may justify revision ofsuch estimate.  Accordingly, reserveestimates are often different from the quantities of oil and natural gas thatare ultimately recovered. In addition, reserve estimates are vulnerable tochanges in wellhead prices of crude oil and natural gas. Such prices have beenvolatile in the past and can be expected to be volatile in the future.

 

***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 jointinterest owners may impact the Company’s overall credit risk in that theseentities may be similarly affected by changes in economic and otherconditions.  Historically, the Companyhas not experienced significant credit losses on such receivables; however, in2001, the Company reserved $525,248 related to non-payments from two purchasersof the Company’s oil and natural gas.  Nobad debt expense was recorded in 2004 or 2003. The Company cannot ensure that similar such losses may not be realizedin the future.

 

***RecentlyIssued Accounting Pronouncements******–*** In December 2004,the FASB issued SFAS No. 123(R), “*Share-BasedPayment.*” This statement requires companies to measure the cost ofemployee services in exchange for an award of equity instruments based on agrant-date fair value of the award (with limited exceptions), and that costmust generally be recognized over the vesting period. SFAS No. 123(R) amendsthe original SFAS No. 123 and 95 that had allowed companies to choose betweenexpensing stock options or showing pro forma disclosure only. This statementeliminates the ability to account for share-based compensation transactionsusing APB Opinion No. 25. We currently account for our stock-based compensationplans under the principles prescribed by APB Opinion No. 25. Accordingly,no stock option compensation cost is reflected in net income, as all optionsgranted under the plan had an exercise price equal to the market value of theunderlying common stock on the date of grant. The adoption of SFAS No. 123(R)will impact our results of operations, but will have no impact on our overallfinancial position. SFAS No. 123(R) becomes effective as of the beginning ofthe first interim or annual reporting period that begins after June 15, 2005.We anticipate adopting the provisions of SFAS No. 123(R) in the thirdquarter of 2005 using the modified prospective method for transition. Underthis method we will recognize compensation expense for all stock-based awardsgranted or modified on or after July 1, 2005, as well as any previouslygranted awards

 

F-12

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that are not fully vested as of July 1, 2005. Compensation expensewill be measured based on the fair value of the awards previously calculated indeveloping the pro forma disclosures in accordance with the provisions ofSFAS No. 123 (see Stock-Based Compensation above). We expect theimpact to be an increase in deferred compensation expense of approximately$80,000 to $100,000 for 2005. SFAS No. 123(R) also requires the benefits of taxdeductions in excess of recognized compensation cost to be reflected as afinancing cash flow, rather than as an operating cash flow as currentlyrequired. We did not recognize any excess tax deductions during 2004, 2003 or2002 in connection with the exercise of stock options.

 

In September 2004, the SEC issued SAB No. 106, *“Interaction of Statement 143 and the Full CostRules,”* which the Company adopted in the fourth quarter of 2004 withno impact on the Company’s financial statements. In accordance with SAB No. 106*,*the amortizable base used to calculateunit-of production depletion includes estimated future development anddismantlement costs, and restoration and abandonment costs, net of estimatedsalvage values.

 

***Reclassifications***-Certain reclassifications of prior period statements have been made to conformto current reporting practices.

 

**3.     ACCOUNTS RECEIVABLE AND ALLOWANCE FORDOUBTFUL ACCOUNTS**

 

Below are the components of Accounts Receivable,Joint Interest Owners and Other, as of December 31, 2004 and 2003:

 
| ** **                                                          | ** ** | **December 31,** | ** ** |
|---------------------------------------------------------------------|------------|------------------|------------|
| ** **                                                          | ** ** | **2004**         | ** ** | **2003** | ** ** |
| ** **                                                          | ** ** | ** **       | ** ** | ** ** | ** ** |
| Joint interest owners                                               |       | $                | 2,351,749  |   | $ | 1,544,445 |   |
| Contango Asset  Acquisition Purchase Price Adjustment (1)           |       | 3,366,400        |       | — |   |
| Other  Receivables (2)                                              |       | 274,924          |       | 335,432 |   |
| Allowance for  Doubtful Accounts Receivable (joint interest owners) |       | (82,000          | )          | (82,000 | ) |
| Net Accounts  Receivable, joint interest owners and other           |       | $                | 5,911,073  |   | $ | 1,797,877 |   |

 

----

(1)                                  Thisamount represents the accrual of revenues, net of expenses for the results ofoperations between November 1, 2004 and December 29, 2004 of the acquiredproperties (see note 6 below).

 

(2)                                  Otherreceivables represent various miscellaneous refunds or credits that the Companyis due that do not relate to Joint Interest Billings or Trade Receivables.

 

The following table setsforth changes in the Company’s allowance for doubtful accounts for the yearsended December 31, 2004, 2003 and 2002:

 
| ** **                         | ** ** | **Balance at  Beginning of  Year** | ** ** | **Charged to  Costs and  Expenses** | ** ** | **Deductions  and Other** | ** ** | **Balance at  End of  Year** | ** ** |
|------------------------------------|------------|------------------------------------|------------|-------------------------------------|------------|---------------------------|------------|------------------------------|------------|
| **Year  ended December 31, 2004:** | ** ** | ** **                         | ** ** | ** **                          | ** ** | ** **                | ** ** | ** **                   | ** ** |
| Allowance for doubtful  accounts   |       | $                                  | 607,248    |                                | $          | —                    |       | $                            | —     |   | $ | 607,248 |   |
| **Year  ended December 31, 2003:** |       |                               |       |                                |       |                      |       |                         |       |
| Allowance for  doubtful accounts   |       | $                                  | 607,248    |                                | $          | —                    |       | $                            | —     |   | $ | 607,248 |   |
| **Year  ended December 31, 2002:** |       |                               |       |                                |       |                      |       |                         |       |
| Allowance for  doubtful accounts   |       | $                                  | 688,248    |                                | $          | —                    |       | $                            | 81,000     |   | $ | 607,248 |   |

 

**4.****              OTHER CURRENT ASSETS**

 

Below are the components of other current assets asof December 31, 2004 and 2003:

 
| ** **                           | ** ** | **December 31,** | ** ** |
|--------------------------------------|------------|------------------|------------|
| ** **                           | ** ** | **2004**         | ** ** | **2003** | ** ** |
| ** **                           | ** ** | ** **       | ** ** | ** ** | ** ** |
| Prepaid  Insurance                   |       | $                | 426,966    |   | $ | 745,499 |   |
| Prepayments and  Deposits to Vendors |       | 498,282          |       | 118,167 |   |
| Inventory (1)                        |       | 520,675          |       | 323,321 |   |
|                                 |       | $                | 1,445,923  |   | $ | 1,186,987 |   |

 

F-13

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----

(1)Consists of tubular goods andproduction equipment for wells and facilities.

 

**5.****              PROPERTY AND EQUIPMENT**

 

At December 31, 2004 and2003, property and equipment consisted of the following:

 
| ** **                                            | ** ** | **December 31,** | ** **  |
|-------------------------------------------------------|------------|------------------|-------------|
| ** **                                            | ** ** | **2004**         | ** **  | **2003** | ** ** |
| Developed oil  and natural gas properties             |       | $                | 243,187,690 |   | $ | 164,419,619 |   |
| Unevaluated oil  and natural gas properties           |       | 15,490,704       |        | 5,044,584 |   |
| Computer  equipment and software                      |       | 4,290,905        |        | 4,124,424 |   |
| Other office  property and equipment                  |       | 1,990,676        |        | 1,682,854 |   |
| Total property  and equipment                         |       | 264,959,975      |        | 175,271,481 |   |
| Accumulated  depletion, depreciation and amortization |       | (99,119,630      | )           | (77,290,724 | ) |
| Total property  and equipment, net                    |       | $                | 165,840,345 |   | $ | 97,980,757 |   |

 

The following tablesummarizes the cost of the properties not subject to amortization by the yearthe cost was incurred:

 
| ** **           | ** ** | **December 31,** | ** ** |
|----------------------|------------|------------------|------------|
| ** **           | ** ** | **2004**         | ** ** | **2003** | ** ** |
| Year cost  incurred: |       |             |       |   |   |
| 1999                 |       | $                | 193,060    |   | $ | 193,060 |   |
| 2000                 |       | 8,611            |       | 8,611 |   |
| 2001                 |       | 108,448          |       | 121,038 |   |
| 2002                 |       | 143,856          |       | 319,188 |   |
| 2003                 |       | 1,506,300        |       | 4,402,687 |   |
| 2004                 |       | 13,530,429       |       | — |   |
| Total                |       | $                | 15,490,704 |   | $ | 5,044,584 |   |

 

**6.****              ACQUISITIONSAND DIVESTITURES**

 

**ContangoAsset Acquisition**

 

On December 29, 2004,the Company consummated the acquisition of interests in oil and natural gasproperties located in south Texas from Contango Oil & Gas Company (“Contango”).The estimated final cash purchase price for the acquisition is $39.8million.  The cash purchase price atclosing was $43.2 million, which was adjusted from the original price of $50.0million for the results of operations between the July 1, 2004 effective dateand October 31, 2004 pursuant to the closing adjustment provisions. At December31, 2004 we have accrued a downward adjustment to the price of $3.4 million,representing the estimated results of operations between November 1, 2004 andthe closing date December 29, 2004,that we anticipate realizing in March 2005pursuant to the post-closing adjustment provisions. The purchase price wasfunded from the net proceeds of a public offering of common stock completedDecember 21, 2004 (see Note 11).

 

Thefollowing unaudited pro forma results for 2004, 2003 and 2002 show the effecton the Company’s consolidated results of operations as if the Contango AssetAcquisition had occurred on January 1, 2002. They are the result of combiningthe statement of income of Edge with the statements of revenues and directoperating expenses for the properties adjusted for (1) the completion of thepublic offering of common stock to finance the cash purchase price, (2)assumption of ARO liabilities and accretion expense for the propertiesacquired, (3) depletion, depreciation and amortization expense applied to theadjusted basis of the properties acquired using the purchase method ofaccounting, and (3) the related income tax effects of these adjustments basedon the applicable statutory rates. The statements of revenues and directoperating expenses for the Contango Assets exclude all other historicalContango expenses.  As a result, certainestimates and judgments were made in preparing the pro forma adjustments,including as to the incremental expenses associated with the Contango Assets.  Thepro forma information includes numerous assumptions, and is not necessarilyindicative of future results of operations:

 

F-14

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| ** **                    | ** ** | **For the Year-Ended December 31,**          | ** ** |
|-------------------------------|------------|----------------------------------------------|------------|
| ** **                    | ** ** | **2004**                                     | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                    | ** ** | **(unaudited)**                              | ** ** |
| ** **                    | ** ** | **(In thousands, except per share amounts)** | ** ** |
| Revenue                       |       | $                                            | 89,941     |   | $ | 65,173 |   | $ | 50,082 |   |
| Net income                    |       | $                                            | 25,816     |   | $ | 17,203 |   | $ | 10,570 |   |
| Net income per  common share: |       |                                         |       |   |   |   |   |
| Basic                         |       | $                                            | 1.51       |   | $ | 1.25 |   | $ | 0.79 |   |
| Diluted                       |       | $                                            | 1.46       |   | $ | 1.23 |   | $ | 0.78 |   |

 

**MillerAcquisition**

 

On December 4, 2003, theCompany completed its merger with Miller Exploration Company (“Miller”).  The Company acquired 100 percent of theoutstanding common stock of Miller in a stock for stock transaction pursuant towhich Miller became a wholly-owned subsidiary of Edge. Under the terms of themerger agreement, each share of issued and outstanding common stock of Millerwas converted into 1.22342 shares of Edge common stock.  Edge issued approximately 2.6 million sharesof Edge common stock to the shareholders of Miller in exchange for all of theoutstanding common stock of Miller. The merger was treated as a tax-freereorganization and accounted for as a purchase business combination.  Under this method of accounting, on the dateof the merger, the assets and liabilities of Miller were recorded by Edge attheir estimated fair market values.

 

Thefollowing unaudited pro forma results for 2003 and 2002 show the effect on theCompany’s consolidated results of operations as if the Miller transactionoccurred on January 1, 2002. They are the result of combining the statement ofincome for Edge with the statement of income for Miller adjusted for (1) therevenue and costs associated with certain Alabama properties sold by Miller inJune of 2003, prior to consummation of the merger, (2) depletion, depreciationand amortization expense of Miller applied to the adjusted basis of theproperties acquired using the purchase method of accounting, and (3) therelated income tax effects of these adjustments based on the applicablestatutory rates. The pro forma data presented is based on numerousassumptions and is not necessarily indicative of future results of operationsor comparable to actual 2004 results of the merged companies.

 
| ** **                    | ** ** | **For the Year-Ended December 31,**          | ** ** |
|-------------------------------|------------|----------------------------------------------|------------|
| ** **                    | ** ** | **2003**                                     | ** ** | **2002** | ** ** |
| ** **                    | ** ** | **(unaudited)**                              | ** ** |
| ** **                    | ** ** | **(In thousands, except per share amounts)** | ** ** |
| Revenue                       |       | $                                            | 43,796     |   | $ | 30,676 |   |
| Net income                    |       | 7,339                                        |       | 171 |   |
| Net income per  common share: |       |                                         |       |   |   |
| Basic                         |       | 0.60                                         |       | 0.01 |   |
| Diluted                       |       | 0.59                                         |       | 0.01 |   |
|                               |            |                                              |            |  |  |  |  |

 

**Divestitures**

 

During 2004, 2003 and2002, the Company sold oil and gas properties for net proceeds of $60,000,$330,096, and $354,294, respectively. Proceeds from these dispositions were credited to the full cost pool.The Company’s 2004 asset divestitures related primarily to the sale of certainoil and gas properties and equipment in Texas, Mississippi and Louisiana. TheCompany’s 2003 asset divestitures related primarily to the sale of the Company’sinterest in affiliated entities, Essex I and II Joint Ventures, and certain oiland gas properties in Texas and Louisiana. The Company’s 2002 divestitures wererelated to the sale of the Company’s interest in certain oil and gas propertiesin Texas, Alabama, Montana and Louisiana.

 

F-15

----

 

**7.     ASSETRETIREMENT OBLIGATIONS**

 

In June 2001, theFASB issued SFAS No. 143, which requires that an asset retirement obligation (“ARO”)associated with the retirement of a tangible long-lived asset be recognized asa liability in the period in which it is incurred and becomes determinable.Under this method, when liabilities for dismantlement and abandonment costs,excluding salvage values, are initially recorded, the carrying amount of therelated oil and gas properties is increased. The fair value of the ARO assetand liability is measured using expected future cash outflows discounted at theCompany’s credit-adjusted risk-free interest rate. Accretion of the liabilityis recognized each period using the interest method of allocation, and thecapitalized cost is depleted over the useful life of the related asset.

 

The Companyadopted SFAS No. 143 on January 1, 2003, which resulted in a net increase tooil and gas properties of $0.4 million and related liabilities of $0.9million.  These amounts reflect the AROof the Company had the provisions of SFAS No. 143 been applied since inceptionand resulted in a non-cash charge to earnings of $357,825 ($550,500 pre-tax).Going forward the Company will record an abandonment liability associated withits oil and gas wells when those assets are placed in service.  The changes to the ARO during the periodsended December 31, 2004 and 2003 are as follows:

 
| ** **                       | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------|------------|-----------------------------|------------|
| ** **                       | ** ** | **2004**                    | ** ** | **2003** | ** ** |
| ARO, beginning  of year          |       | $                           | 1,811,995  |   | $ | 942,736 |   |
| Additional  liabilities incurred |       | 676,099                     |       | 997,057 |   |
| Liabilities  settled             |       | (397,974                    | )          | (85,164 | ) |
| Accretion  expense               |       | 98,968                      |       | 66,625 |   |
| Revisions                        |       | —                      |       | (109,259 | ) |
| ARO, end of year                 |       | $                           | 2,189,088  |   | $ | 1,811,995 |   |
|                             |       |                        |       |   |   |
| Current Portion                  |       | $                           | 193,647    |   | $ | 323,513 |   |
| Long-term  Portion               |       | $                           | 1,995,441  |   | $ | 1,488,482 |   |

 

ARO liabilities incurredduring the year ended December 31, 2004 include obligations assumed for 39wells acquired in south Texas from Contango on December 29, 2004, as well asobligations for all successful wells drilled during the year.  Liabilities settled during the year endedDecember 31, 2004 included 32 wells that were either plugged or sold.

 

The following tablesummarizes the pro forma net income and earnings per share for the year endedDecember 31, 2002 had SFAS 143 been adopted by the Company on January 1, 2002.

 
| ** **                     | ** ** | **For the Year Ended  December 31, 2002** | ** ** |
|--------------------------------|------------|-------------------------------------------|------------|
| ** **                     | ** ** | **As Reported**                           | ** ** | **Pro Forma** | ** ** |
| Net income                     |       | $                                         | 749,745    |   | $ | 715,192 |   |
| Net income per  share, basic   |       | $                                         | 0.08       |   | $ | 0.08 |   |
| Net income per  share, diluted |       | $                                         | 0.08       |   | $ | 0.07 |   |

 

Had the Company appliedthe provisions of SFAS No. 143 in the previous periods, the pro forma amount ofthe ARO liability would have been $882,537 at January 1, 2002.

 

**8.****              ACCRUED LIABILITIES**

 

Beloware the components of accrued liabilities as of December 31, 2004 and 2003:

 

F-16

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| ** **                                                                 | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------------------|------------|------------------|------------|
| ** **                                                                 | ** ** | **2004**         | ** ** | **2003** | ** ** |
| ** **                                                                 | ** ** | ** **       | ** ** | ** ** | ** ** |
| Accrued capital  expenditures                                              |       | $                | 4,653,450  |   | $ | 4,751,882 |   |
| Professional  services                                                     |       | 1,021,165        |       | 304,067 |   |
| Salary and  benefits                                                       |       | 1,045,547        |       | 579,537 |   |
| Royalties  payable                                                         |       | 4,451,094        |       | 3,283,521 |   |
| Lease operating  expenses including severance and ad valorem taxes payable |       | 1,047,413        |       | 1,325,195 |   |
| Other                                                                      |       | 846,818          |       | 1,211,834 |   |
| **Total  Accrued Liabilities**                                             |       | $                | 13,065,487 |   | $ | 11,456,036 |   |

 

**9.****              HEDGING AND DERIVATIVEACTIVITIES**

 

Due to the volatility ofoil and natural gas prices, the Company periodically enters into price-riskmanagement transactions (e.g., swaps, collars and floors) for a portion of itsoil and natural gas production to achieve a more predictable cash flow, as wellas to reduce exposure from price fluctuations. While the use of these arrangements limits the Company’s ability tobenefit from increases in the price of oil and natural gas, it also reduces theCompany’s potential exposure to adverse price movements.  The Company’s arrangements, to the extent itenters into any, apply to only a portion of its production, provide onlypartial price protection against declines in oil and natural gas prices andlimit the Company’s potential gains from future increases in prices.  None of these instruments are used fortrading or speculative purposes. On a quarterly basis, the Company’s managementsets all of the Company’s price-risk management policies, including volumes,types of instruments and counterparties. These policies are implemented bymanagement through the execution of trades by the Chief Financial Officer afterconsultation and concurrence by the President and Chairman of the Board.  The Board of Directors monitors the Company’spolicies and trades.

 

All of these price-riskmanagement transactions are considered derivative instruments and accounted forin accordance with SFAS No. 133, *“Accountingfor Derivative Instruments and Hedging Activities”*. These derivativeinstruments are intended to hedge our price risk and may be considered hedgesfor economic purposes, but certain of these transactions may not qualify forcash flow hedge accounting. All derivative instrument contracts are recorded onthe balance sheet at fair value. For those derivative instrument contracts thatqualify for cash flow hedge accounting, the effective portion of the changes inthe fair value of the contracts is recorded in other comprehensive income andthe ineffective portion of the changes in the fair value of the contracts isrecorded in revenue as they occur. While the contract is outstanding, theineffective gain or loss may increase or decrease until settlement of thecontract depending on the fair value at the measurement dates. When the hedgedproduction is sold, the realized gains and losses on the contracts are removedfrom other comprehensive income and recorded in revenue. The Company iscurrently accounting for its natural gas contracts as cash flow hedges offuture cash flows from the sale of natural gas. For those derivative instrumentcontracts that either do not qualify for cash flow hedge accounting or theCompany does not designate as hedges of future cash flows, the changes in fairvalue are not deferred through other comprehensive income, but rather recordedin revenue immediately as unrealized gains or losses. The Company did not applycash flow hedge accounting to its crude oil collars entered into in 2004,because although they were economic hedges, they did not qualify for hedgeaccounting.

 

For the year endedDecember 31, 2004, 2003 and 2002, the Company included in revenue realized andunrealized losses related to its natural gas hedges and oil derivatives. Therewas no ineffectiveness recognized during the years ended December 31, 2004,2003 and 2002. The impact on total revenue from hedging activities for thethree years ended December 31, 2004, 2003 and 2002 was as follows:

 
| ** **                                               | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                               | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| Natural gas  hedging contract settlements                |       | $                           | (328,500   | ) | $ | (4,455,590 | ) | $ | (326,950 | ) |
| Crude oil  derivative contract settlements               |       | (880,765                    | )          | — |   | — |   |
| Hedge premium  reclassification                          |       | (686,250                    | )          | — |   | — |   |
| Oil derivative  contract unrealized change in fair value |       | (564,548                    | )          | — |   | — |   |
| Loss on hedging  and derivatives                         |       | $                           | (2,460,063 | ) | $ | (4,455,590 | ) | $ | (326,950 | ) |

 

F-17

----

 

The outstanding hedges atDecember 31, 2004, 2003, and 2002 impacting the balance sheet were as follows: 

 
| ** **             | ** ** | ** **            | ** ** | ** **    | ** ** | ** ** | ** ** | ** **    | ** ** | ** **  | ** ** | **Fair  Value of Outstanding Hedging and  Derivative Contracts as of** | ** ** |
|------------------------|------------|-----------------------|------------|---------------|------------|------------|------------|---------------|------------|-------------|------------|------------------------------------------------------------------------|------------|
| ** **             | ** ** | ** **            | ** ** | ** **    | ** ** | ** ** | ** ** | **Price**     | ** ** | **Volumes** | ** ** | **December  31,**                                                      | ** ** |
| **Transaction Date**   | ** ** | **Transaction  Type** | ** ** | **Beginning** | ** ** | **Ending** | ** ** | **Per Unit**  | ** ** | **Per Day** | ** ** | **2004 (5)**                                                           | ** ** | **2003** | ** ** |
| ***Natural Gas (1):*** |       |                  |       |          |       |       |       |          |       |        |       |                                                                   |       |   |   |
| 12/03                  |       | Natural Gas Collar    |       | 01/01/2004    |       | 03/31/2004 |       | $4.50-$7.05   |       | 5,000MMbtu  |       | $                                                                      | —     |   | $ | 37,688 |   |
| 08/03                  |       | Natural Gas Collar    | (2)        | 01/01/2004    |       | 03/31/2004 |       | $4.50-$7.00   |       | 10,000MMbtu |       | —                                                                 |       | (91,504 | ) |
| 08/03                  |       | Natural Gas Collar    | (2)        | 04/01/2004    |       | 09/30/2004 |       | $4.50-$6.00   |       | 10,000MMbtu |       | —                                                                 |       | 42,996 |   |
| 08/03                  |       | Natural Gas Collar    | (2)        | 10/01/2004    |       | 12/31/2004 |       | $4.50-$7.00   |       | 10,000MMbtu |       | —                                                                 |       | 131,621 |   |
| 05/04                  |       | Natural Gas Collar    |       | 01/01/2005    |       | 03/31/2005 |       | $5.00-$10.39  |       | 10,000MMbtu |       | 92,703                                                                 |       | — |   |
| 07/04                  |       | Natural Gas Collar    |       | 04/01/2005    |       | 06/30/2005 |       | $5.00-$7.53   |       | 10,000MMbtu |       | 9,162                                                                  |       | — |   |
| 07/04                  |       | Natural Gas Collar    |       | 07/01/2005    |       | 09/30/2005 |       | $5.00-$7.67   |       | 10,000MMbtu |       | (41,210                                                                | )          | — |   |
| 10/04                  |       | Natural Gas Collar    |       | 01/01/2005    |       | 12/31/2005 |       | $6.00-$9.52   |       | 10,000MMbtu |       | 1,860,375                                                              |       | — |   |
| ***Crude Oil (3):***   |       |                  |       |          |       |       |       |          |       |        |       |                                                                   |       |   |   |
| 03/04                  |       | Crude Oil Collar      |       | 04/01/2004    |       | 12/31/2004 |       | $30.00-$35.50 |       | 400Bbl      |       | (96,240                                                                | )          | — |   |
| 05/04 (08/04) (4)      |       | Crude Oil Collar      |       | 01/01/2005    |       | 12/31/2005 |       | $35.00-$40.00 |       | 200/290Bbl  |       | (468,308                                                               | )          | — |   |
|                   |       |                  |       |          |       |       |       |          |       |        |       | $                                                                      | 1,356,482  |   | $ | 120,801 |   |

 

----

(1).       TheCompany’s current hedging activities for natural gas were entered into on a perMMbtu delivered price basis, using the Houston Ship Channel Index, withsettlement for each calendar month occurring five business days following theexpiration date.

(2).       This contract was enteredinto at a cost of $686,250.

(3).       Hedge accounting is notapplied to the Company’s collars on crude oil, which were entered into on a perbarrel delivered price basis, using the West Texas Intermediate Index, withsettlement for each calendar month occurring five business days following theexpiration date. The change in fair value is reflected in net revenue for theyear ended December 31, 2004.

(4).       In August 2004, the Companyreplaced the contract that was entered into May 2004 with a new contract thatchanges the volume and pricing terms. The put option is on 200 Bbl/D and thecall option is on 290 Bbl/D. This transaction was completed at no additionalcost to the Company.

(5).       The fair value of theCompany’s outstanding transactions is presented on the balance sheet bycounterparty. Our counterparties net our positions with them, but we cannotpresent the net of the two counterparty positions because we do not have legalright of offset. Therefore one counterparty is presented in the DerivativeAsset and one is presented in the Derivative Liability. The crude oil collarwith a balance of ($468,308) is presented as a liability and the remainingcontracts are presented as an asset. All contracts are considered current.

 

**10.****                               LONG-TERMDEBT**

 

In March 2004, theCompany entered into a new amended and restated credit facility (the “CreditFacility”), effective December 31, 2003, which permits borrowings up to thelesser of (i) the borrowing base and (ii) $100.0 million.  Borrowings under the Credit Facility bearinterest at a rate equal to prime plus 0.50% or LIBOR plus 2.25%.  At December 31, 2004 the interest rateapplied to our outstanding balance was 5.75%. As of December 31, 2004, $20.0million in borrowings were outstanding under the Credit Facility.  The Credit Facility matures December 31, 2006and is secured by substantially all of the Company’s assets.

 

Effective December 29,2004, the Credit Facility’s borrowing base was increased from $48.0 million to$65.0 million. The borrowing base under the Credit Facility was increased as aresult of the Contango Asset Acquisition and our drilling activities since thelast redetermination.  The Company’savailable borrowing capacity under this facility was $45.0 million at December31, 2004.

 

The Credit Facilityprovides for certain restrictions, including but not limited to, limitations onadditional borrowings, sales of oil and natural gas properties or othercollateral, and engaging in merger or consolidation

 

F-18

----

 

transactions. The CreditFacility also prohibits dividends and certain distributions of cash orproperties and certain liens.  The CreditFacility also contains the following financial covenants, among others:

 

•                  TheEBITDAX to Interest Expense ratio requires that the ratio of (a) consolidatedEBITDAX (defined as EBITDA plus similar non-cash items and exploration andabandonment expenses for such period) of the Company for the four fiscalquarters then ended to (b) the consolidated interest expense of the Company forthe four fiscal quarters then ended, not be less than 3.5 to 1.0.

•                  TheWorking Capital ratio requires that the amount of the Company’s consolidatedcurrent assets less its consolidated current liabilities, as defined in theagreement, be at least $1.0 million. For the purposes of calculating the WorkingCapital ratio, current assets is adjusted for unused capacity under creditagreement and hedging and derivative assets and current liabilities is adjustedfor derivative and hedging liabilities and asset retirement obligations.

•                  TheMaximum Leverage ratio requires that the ratio, as of the last day of anyfiscal quarter, of (a) Total Indebtedness (as defined in the Credit Facility)as of such fiscal quarter to (b) an amount equal to consolidated EBITDAX forthe two quarters then ended times two, not be greater than 3.0 to 1.0.

 

Consolidated EBITDAX is acomponent of negotiated covenants with our lender and is presented here as partof the Company’s disclosure of its covenant obligations.

 

**11.****       SHELF REGISTRATIONSTATEMENT**

 

The Company filed a $150 million shelf registration statement with the SEC, which became effective in May 2004. Under the shelf registration statement, the Company may issue, from time to time, any combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities in one or more offerings to those persons who agree to purchase our securities. Net proceeds, terms and pricing of the offering of securities issued under the shelf registration statement will be determined at the time of the offerings. The shelf registration statement does not provide assurance that the Company will or could sell any such securities. The Company’s ability to utilize this shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities will depend upon, among other things, market conditions and the existence of investors who wish to purchase the Company’s securities at prices acceptable to the Company.

 

The Company completed an offering on December 21, 2004 of3.5 million shares of its common stock under the Company’s shelf registrationstatement, which generated net proceeds to us, before direct costs of theoffering, of $47.8 million. These funds were used to finance the Contango AssetAcquisition preliminary adjusted purchase price of $43.2 million (see Note 6)and fund other general corporate purposes. On January 5, 2005, the underwritersexercised their over-allotment option for an additional 525,000 shares ofcommon stock, which generated net proceeds to us of $7.2 million. These fundswere used to reduce outstanding debt. Each of these sales was made under ourshelf registration statement such that, at March 16, 2005, the Company had$91.8 million remaining for issuance under the shelf registration.

 

**12.****       COMMITMENTS ANDCONTINGENCIES**

 

***Commitments -***At December 31, 2004,the Company was obligated under noncancelable operating leases.  Following is a schedule of the remainingfuture minimum lease payments under these leases:

 

F-19

----

 
| 2005      |   | $         | 629,200   |   |
|-----------|--------|-----------|-----------|--------|
| 2006      |   | 621,300   |      |
| 2007      |   | 621,300   |      |
| 2008      |   | 631,200   |      |
| 2009      |   | 622,400   |      |
| Remainder |   | 2,230,200 |      |
| Total     |   | $         | 5,355,600 |   |

 

Rent expense for theyears ended December 31, 2004, 2003 and 2002 was approximately $474,300,442,700, and $566,700, respectively.

 

***Contingencies -***From time to time theCompany is a party to various legal proceedings arising in the ordinary courseof business.  While the outcome oflawsuits cannot be predicted with certainty, the Company is not currently aparty to any proceeding that it believes, if determined in a manner adverse tothe Company, could have a potential material adverse effect on its financialcondition, results of operations or cash flows.

 

Additionally, the Company’soperations are subject to numerous laws and regulations governing the dischargeof materials into the environment or otherwise relating to environmentalprotection.  Public interest in theprotection of the environment has increased dramatically in recent years.  The trend of more expansive and stricterenvironmental legislation and regulations could continue.  To the extent laws are enacted or other governmentalaction is taken that restricts drilling or imposes environmental protectionrequirements that result in increased costs to the oil and natural gas industryin general, the business and prospects of the Company could be adverselyaffected.

 

***Duringthe second quarter of 2004, the Company received notice that its franchise taxreturns for the State of Texas would be audited for the tax years 1999 through2002. After reviewing documents submitted, the agent representing the Office ofthe Comptroller of the State of Texas proposed adjustments to the calculationthat would result in an increased franchise tax liability.  The agent maintained that transfers by theparent company to its subsidiaries that the Company classified as intercompanyloans should instead be classified as equity investments in the subsidiary. TheState of Texas originally proposed that the franchise tax liability of thesubsidiaries would be increased by approximately $3.0 million for the four-yearperiod under audit.***

*** ***

Duringthe third quarter of 2004 the agent reduced the proposed franchise taxdeficiency adjustment to the Company and its subsidiaries to an aggregate $467,000.The Company intends to vigorously contest this proposed franchise taxassessment through appropriate administrative levels in the Comptroller’sOffice.  In the fourth quarter of 2004,there was an informal hearing at the local Comptroller’s Office during whichthe agent indicated he would formally assess the proposed deficiency.  The Company has not received any suchdeficiency adjustment, but if it does, it intends to continue to vigorouslycontest the assessment through appropriate administrative levels in the Comptroller’sOffice and any other available means.  Dueto its intention to continue to vigorously contest the proposed adjustments,the Company has not recognized any provision for the additional franchise taxesthat would result from the proposed deficiency.

 

**13.****       SALES TO MAJOR CUSTOMERS AND OPERATORS**

 

In accordance withStatement of Financial Accounting Standards No. 131 (“SFAS No. 131”), *Disclosures about Segments of an Enterprise andRelated Information*, public business enterprises are required toreport financial and other information about operating segments of the entityfor which such information is available and is utilized by the chief operatingdecision maker. SFAS No. 131 also establishes standards for related disclosuresabout products and services, geographic area, and major customers. The Companyoperates as one business segment. We sold natural gas and crude oil productionrepresenting 10% or more of our total revenues for the years ended December 31,2004, 2003, and 2002 as listed below:

 

 
| ** **                    | ** ** | **For the year ended December 31,** | ** ** |
|-------------------------------|------------|-------------------------------------|------------|
| **Major Purchaser**           | ** ** | **2004**                            | ** ** | **2003** | ** ** | **2002** | ** ** |
| Upstream Energy  Services (1) |       | 22                                  | %          |   | 38 | % |   | 24 | % |   |
| ChevronTexaco                 |       | 22                                  | %          |   | 6 | % |   | 18 | % |   |
| Copano Field  Services        |       | 19                                  | %          |   | 16 | % |   | 17 | % |   |
| BTA                           |       | 2                                   | %          |   | 18 | % |   | 5 | % |   |
| Southwestern  Energy          |       | 1                                   | %          |   | 5 | % |   | 15 | % |   |

 

F-20

----

 

----

NOTE: Amounts disclosedare approximations and those that are less than 10% are presented forinformation and comparison purposes only. Also these percentages do notconsider the effects of financial hedges.

 

(1) Upstream is an agentthat sells our production to other purchasers on our behalf.

 

In the exploration,development and production business, production is normally sold to relativelyfew customers. A significant portion of our sales are made on our behalf by theoperators of the properties and therefore these entities may be listed above.Substantially all of the Company’s customers are concentrated in the oil and gasindustry and revenue can be materially affected by current economic conditionsand the price of certain commodities such as natural gas and crude oil, thecost of which is passed through to the customer. However, based on the currentdemand for natural gas and crude oil and the fact that alternate purchasers arereadily available, we believe that the loss of any of our major purchaserswould not have a long-term material adverse effect on our operations.

 

**14.****       INCOME TAXES**

 

Deferred income taxesreflect the tax effects of temporary differences between the carrying amountsof assets and liabilities for financial reporting purposes and the amountscalculated for income tax purposes in accordance with SFAS No. 109.  Significant components of the Company’s deferredtax liabilities and assets as of December 31, 2004 and 2003 are as follows:

 
| ** **                                                           | ** ** | **December 31,** | ** **  |
|----------------------------------------------------------------------|------------|------------------|-------------|
| ** **                                                           | ** ** | **2004**         | ** **  | **2003** | ** ** |
| Deferred tax  liability:                                             |       |             |        |   |   |
| Book basis of  oil and natural gas properties in excess of tax basis |       | $                | (28,874,455 | ) | $ | (12,479,467 | ) |
| Deferred tax  assets:                                                |       |             |        |   |   |
| Net operating  loss carryforwards                                    |       | 25,857,283       |        | 17,548,865 |   |
| Expenses not  currently deductible for tax purposes                  |       | 350,000          |        | 192,500 |   |
| Accretion on ARO                                                     |       | 130,563          |        | 95,924 |   |
| Deferred  compensation                                               |       | 572,304          |        | 531,479 |   |
| Federal  alternative minimum tax credits                             |       | 75,000           |        | 75,000 |   |
| Price risk  management liability                                     |       | (474,766         | )           | 201,976 |   |
| Other                                                                |       | 405,360          |        | 542,352 |   |
| Total deferred  tax asset                                            |       | 26,915,744       |        | 19,188,096 |   |
| Net deferred tax  asset (liability)                                  |       | $                | (1,958,711  | ) | $ | 6,708,629 |   |

 

Tax benefits of $462,020and $137,141 for the year ended December 31, 2004 and 2003, respectively, arereflected as a component of equity. These tax benefits relate to the exerciseof qualified stock options and the vesting of restricted stock at prices higherthan those used for financial reporting purposes.  Upon adoption of SFAS No. 143 on January 1,2003, the Company recorded a cumulative effect of change in accountingprinciple of $357,825, after taxes of $192,675.

 

The Company’s provision(benefit) for income taxes consists of the following:

 
| ** ** | ** ** | **2004**  | ** ** | **2003**  | ** ** | **2002**  | ** ** |
|------------|------------|-----------|------------|-----------|------------|-----------|------------|
| Current    |       | $         | —     |      | $          | —    |       | $ | — |   |
| Deferred   |       | 8,255,025 |       | 2,731,132 |       | 473,060   |       |
| Total      |       | $         | 8,255,025  |      | $          | 2,731,132 |       | $ | 473,060 |   |

 

F-21

----

 

The differences betweenthe statutory federal income taxes calculated using a federal tax rate of 35%and the Company’s effective tax rate is summarized as follows:

 
| ** **                                          | ** ** | **2004** | ** ** | **2003** | ** ** | **2002**  | ** ** |
|-----------------------------------------------------|------------|----------|------------|----------|------------|-----------|------------|
| Statutory  federal income taxes                     |       | $        | 8,184,496  |     | $          | 2,603,653 |       | $ | 427,982 |   |
| Expenses not  deductible for tax purposes and other |       | 70,529   |       | 127,479  |       | 45,078    |       |
|                                                |       |     |       |     |       |      |       |
| Income tax  expense                                 |       | $        | 8,255,025  |     | $          | 2,731,132 |       | $ | 473,060 |   |

 

At December 31, 2004, theCompany had cumulative net operating loss carryforwards (“NOLs”) for federalincome tax purposes of approximately $73.9 million that expire beginning 2007through 2022.  The Company believes thatit is more likely than not that it will utilize all of these NOLs in connectionwith federal income taxes generated in the future.  The estimated NOLs presented herein assumethat certain items, primarily intangible drilling costs, have been written offfor tax purposes in the current year. However, the Company has not made a final determination if an electionwill be made to capitalize all or part of these items for tax purposes in thefuture.

 

**15.****       EMPLOYEE BENEFIT PLANS**

 

***Effective July 1, 1997, the Company established adefined-contribution 401(k) Savings & Profit Sharing Plan Trust (the “Plan”)covering employees of the Company who are age 21 or older.  The Company’s matching contributions to thePlan are discretionary.  For the yearsended December 31, 2004, 2003 and 2002, the Company contributed approximately$121,300, $74,200, and $83,200, respectively, to the Plan.***

*** ***

**16.****       EQUITY AND STOCK PLANS**

 

***Private Offering –*** In connection with a privateoffering on May 6, 1999 of 1,400,000 shares of common stock at a price of $5.40per share the Company issued warrants for $0.125 per warrant, to acquire anadditional 420,000 shares of common stock at $5.35 per share and wereexercisable through May 6, 2004. All of these warrants have now been exercised.At the election of the Company, the warrants could have been called at aredemption price of $0.01 per warrant at any time after any date at which theaverage daily per share closing bid price for the immediately preceding 20consecutive trading days exceeds $10.70. In November and December of 2003, 375,000 warrants were exercised forproceeds of approximately $2.0 million. In March 2004 Mr. Elias, our Chairman and Chief Executive Officer,exercised the remaining warrants, which resulted in the Company’s issuance tohim of 45,000 shares of common stock and net proceeds to us of $240,750.

 

***Public Offering*** ***-*** In connection with a public offering onDecember 21, 2004, the Company issued 3,500,000 shares of common stock at agross price of $14.45 per share. This offering generated net proceeds to us,after underwriter’s fees and before direct costs of the offering, of $47.8million. These shares were issued to generate funds to finance the ContangoAsset Acquisition that was completed December 29, 2004.

 

***Stock Plans*** - In conjunction with the Offering, the Company established theIncentive Plan of Edge Petroleum Corporation (the “Incentive Plan”). TheIncentive Plan is discretionary and provides for the granting of awards,including options for the purchase of the Company’s common stock and for theissuance of restricted and/or unrestricted common stock to directors, officers,employees and independent contractors of the Company.  The options and restricted stock granted todate vest over periods of 2-3 years.  TheCompany amended the Incentive Plan in December 2003, to increase the sharesavailable under the plan from 1.2 million to 1.7 million.  An aggregate of 1,700,000 shares of commonstock have been reserved for grants under the Incentive Plan, of which 495,798shares were available for future grants at December 31, 2004. The followingnonqualified stock option awards and restricted stock grants were made underthe Incentive Plan during each of the years indicated below:

 

F-22

----

 
| ** **                      | ** ** | **Number  Granted** | ** ** | **Market Value on   Date of Grant** | ** ** |
|---------------------------------|------------|---------------------|------------|-------------------------------------|------------|
| ***Options  Awards:***          |       |                |       |                                |       |
| 2004                            |       | 13,000              |       | $13.99                              |       |
| 2003                            |       | 32,000              |       | $3.88 to $5.73                      |       |
| 2002                            |       | 175,800             |       | $3.40 to $5.69                      |       |
|                            |       |                |       |                                |       |
| ***Restricted  Stock Awards:*** |       |                |       |                                |       |
| 2004                            |       | 94,676              |       | $10.09 to $16.89                    |       |
| 2003                            |       | 91,400              |       | $3.88 to $6.80                      |       |
| 2002                            |       | 10,800              |       | $5.01 to $5.18                      |       |

 

Stock option awards vest100 percent two years from date of grant.  Shares of common stock associated with the restricted stock awards willbe issued, subject to continued employment, ratably over three years inaccordance with the award’s vesting schedule, beginning on the firstanniversary of the date of grant. Compensation expense from restricted stock is amortized over the vestingperiod and offset to additional paid in capital. Below is a summary ofamortization of deferred compensation related to restricted stock awards forthe years indicated:

 

 
| **Year Ended December 31,** | ** ** | **Deferred  Compensation  Expense** | ** ** |
|-----------------------------|------------|-------------------------------------|------------|
| 2004                        |       | $                                   | 498,372    |   |
| 2003                        |       | 372,151                             |       |
| 2002                        |       | 399,249                             |       |
|                             |            |                                     |            |  |

 

Effective May 21, 1999,the Company amended and restated the Incentive Plan.  In conjunction with those and other****amendments of the Incentive Plan, the Company exchanged, ona voluntary basis, 556,488 outstanding nonqualified stock options of certainemployees and Directors of the Company for 326,700 new common stock options inreplacement of those options.   Theexercise price of the replacement options was $7.06 per share, which representsthe fair market value on the date of grant. The replaced options have a ten-year term with 50% of the optionsvesting immediately on the date of grant with the remaining 50% vesting on May21, 2000.   On May 21, 1999, inconjunction with the repricing, the Company also issued 99,800 new ten-yearcommon stock options to employees, which vested 100 percent on May 21,2001.  The exercise price of the newoptions was $7.06, which represents the fair market value on the date of grant.  On June 1, 1999, the Company issued 21,000ten-year common stock options to non-employee directors with an exercise priceof $7.28 per share, which represented their fair market value at the date ofgrant, vesting 100 percent on June 1, 2001.

 

Deferred compensationcost reported in accordance with FIN 44 (see Note 2 above) included a charge for the year endedDecember 31, 2004.  Below is a summary ofFIN 44 charges related to the variable accounting for certain re-priced stockoptions impacting the Company’s statement of operations for the yearsindicated:

 
| **Year Ended December 31,** | ** ** | **Charge** | ** ** |
|-----------------------------|------------|------------|------------|
| 2004                        |       | $          | 1,135,628  |   |
| 2003                        |       | 1,219,349  |       |
| 2002                        |       | 3,385      |       |
|                             |            |            |            |  |

 

As a component of hisemployment agreement with the Company, John Elias, CEO and Chairman of theBoard, has been granted option awards and a restricted stock award outside ofthe Incentive Plan. Mr. Elias has also been granted some options and restrictedstock under the Incentive Plan. The options vest and become exercisable over a

 

F-23

----

 

two or three year periodsubsequent to issue.  The restrictedstock is issued ratably over three years in accordance with the award’s vestingschedule, beginning on the first anniversary of the date of grant.  Compensation expense is amortized over thevesting period and offset to additional paid in capital.  The amortization of compensation expenserelated to this award was included in the amounts discussed above.   Below is a summary of option and restrictedstock grants to Mr. Elias made outside of the Incentive Plan:

 
| **Date  Granted**           | ** ** | **Shares  Outstanding** | ** ** | **Exercise  Price** | ** ** | **Date  Exercisable**                                                             |
|-----------------------------|------------|-------------------------|------------|---------------------|------------|-----------------------------------------------------------------------------------|
|                        |       |                    |       |                |       |                                                                              |
| ***Options (1):***          |       |                    |       |                |       |                                                                              |
| 01/08/1999                  |       | 200,000                 |       | $                   | 4.22       |                                                                              | One-third upon issue  and one-third upon each of January 1, 2000 and 2001 |
| 01/03/2000                  |       | 50,000                  |       | $                   | 3.16       |                                                                              | 100% January 2002 |
| 01/03/2001                  |       | 50,000                  |       | $                   | 8.88       |                                                                              | 100% January 2003 |
| 01/03/2002                  |       | 50,000                  |       | $                   | 5.18       |                                                                              | 100% January 2004 |
| 04/02/2002                  |       | 24,000                  |       | $                   | 5.59       |                                                                              | 100% April 2004 |
| 01/23/2003                  |       | 50,000                  |       | $                   | 3.88       |                                                                              | 100% January 2005 |
| 04/01/2004                  |       | 37,000                  |       | $                   | 13.99      |                                                                              | 100% January 2006 |
|                        |       |                    |       |                |       |                                                                              |
| ***Restricted Stock (2):*** |       |                    |       |                |       |                                                                              |
| 04/02/2001                  |       | 14,000                  |       |                |       | Ratably over three  years beginning on the first anniversary of the date of grant |

 

----

(1)          Exerciseprice equals the fair market value on the date of grant.

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

 

A summary of the statusof the Company’s stock options and changes as of and for each of the threeyears ended December 31, 2004 is presented below:

 
| ** **                                                        | ** ** | **2004**   | ** ** | **2003**                               | ** ** | **2002**   | ** ** |
|-------------------------------------------------------------------|------------|------------|------------|----------------------------------------|------------|------------|------------|
| ** **                                                        | ** ** | **Shares** | ** ** | **Weighted  Average  Exercise  Price** | ** ** | **Shares** | ** ** | **Weighted  Average  Exercise  Price** | ** ** | **Shares** | ** ** | **Weighted  Average  Exercise  Price** | ** ** |
| Outstanding,  January 1                                           |       | 1,171,512  |       | $                                      | 8.76       |       | 1,098,050  |   | $ | 5.62 |   | 866,200 |   | $ | 5.62 |   |
| Granted                                                           |       | 50,000     |       | $                                      | 13.99      |       | 82,000     |   | $ | 4.35 |   | 273,800 |   | $ | 5.46 |   |
| Assumed in  merger                                                |       | —     |       | —                                 |       | 120,138    |       | $ | 39.76 |   | — |   | — |   |
| Forfeited                                                         |       | (76,739    | )          | $                                      | 59.11      |       | (24,000    | ) | $ | 6.04 |   | (24,650 | ) | $ | 5.70 |   |
| Exercised                                                         |       | (322,723   | )          | $                                      | 6.24       |       | (104,676   | ) | $ | 4.07 |   | (17,300 | ) | $ | 3.01 |   |
| Outstanding,  December 31                                         |       | 822,050    |       | $                                      | 5.91       |       | 1,171,512  |   | $ | 9.14 |   | 1,098,050 |   | $ | 5.62 |   |
|                                                              |       |       |       |                                   |       |       |       |   |   |   |   |   |   |
| Exercisable,  December 31,                                        |       | 690,050    |       | $                                      | 5.51       |       | 843,412    |   | $ | 10.67 |   | 752,050 |   | $ | 5.34 |   |
|                                                              |       |       |       |                                   |       |       |       |   |   |   |   |   |   |
| Weighted average  fair value of options granted during the period |       | $          | 13.99      |                                   |       |       | $          | 3.23 |   |   |   | $ | 4.19 |   |   |   |
|                                                                   |            |            |            |                                        |            |            |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

A summary of the Company’sstock options categorized by class of grant at December 31, 2004 is presentedbelow:

 

F-24

----

 
| **All Options**              | ** ** | **Options Exercisable** |
|------------------------------|------------|-------------------------|
| **Range of  Exercise Price** | ** ** | **Shares  Outstanding** | ** ** | **Weighted  Average  Remaining  Contractual  Life** | ** ** | **Weighted  Average  Exercise  Price** | ** ** | **Range of  Exercise  Price** | ** ** | **Shares  Outstanding** | ** ** | **Weighted  Average  Exercise  Price** |
| $3.00 - $3.88                |       | 141,700                 |   | 6.38 |   | $ | 3.44 |   | $3.00 - $3.16 |   | 80,700 |   | $ | 3.12 |
| $4.22                        |       | 200,000                 |   | 4.01 |   | $ | 4.22 |   | $4.22 |   | 200,000 |   | $ | 4.22 |
| $5.18 - $5.73                |       | 199,900                 |   | 7.32 |   | $ | 5.49 |   | $5.18-$5.69 |   | 178,900 |   | $ | 5.46 |
| $7.06 - $7.58                |       | 180,350                 |   | 4.52 |   | $ | 7.11 |   | $7.06 - $7.58 |   | 180,350 |   | $ | 7.11 |
| $8.88                        |       | 50,000                  |   | 6.01 |   | $ | 8.88 |   | $8.88 |   | 50,000 |   | $ | 8.88 |
| $13.50-$13.99                |       | 50,100                  |   | 9.24 |   | $ | 13.99 |   | $13.50 |   | 100 |   | $ | 13.50 |

 

***Computation ofEarnings per Share -***The following is presented as areconciliation of the numerators and denominators of basic and diluted earningsper share computations, in accordance with SFAS No. 128.

 
| ** **                               | ** ** | **Year Ended December 31, 2004** | ** ** |
|------------------------------------------|------------|----------------------------------|------------|
| ** **                               | ** ** | **Income  (Numerator)**          | ** ** | **Shares  (Denominator)** | ** ** | **Per Share  Amount** | ** ** |
| **Basic  EPS**                           |       |                             |       |   |   |   |   |
| Income available  to common stockholders |       | $                                | 15,129,250 |   | 13,029,075 |   | $ | 1.16 |   |
| **Effect  of Dilutive Securities**       |       |                             |       |   |   |   |   |
| Common stock  options                    |       | —                           |       | 476,823 |   | (0.04 | ) |
| Restricted stock                         |       | —                           |       | 142,363 |   | (0.01 | ) |
| **Diluted  EPS**                         |       |                             |       |   |   |   |   |
| Income available  to common stockholders |       | $                                | 15,129,250 |   | 13,648,261 |   | $ | 1.11 |   |

 
| ** **                               | ** ** | **Year Ended December 31, 2003** | ** ** |
|------------------------------------------|------------|----------------------------------|------------|
| ** **                               | ** ** | **Income  (Numerator)**          | ** ** | **Shares  (Denominator)** | ** ** | **Per Share  Amount** | ** ** |
| **Basic  EPS**                           |       |                             |       |   |   |   |   |
| Income available  to common stockholders |       | $                                | 4,350,050  |   | 9,726,140 |   | $ | 0.45 |   |
| **Effect  of Dilutive Securities**       |       |                             |       |   |   |   |   |
| Common stock  options                    |       | —                           |       | 148,618 |   | (0.01 | ) |
| Restricted stock                         |       | —                           |       | 110,379 |   | — |   |
| Warrants                                 |       | —                           |       | 2,414 |   | — |   |
| **Diluted  EPS**                         |       |                             |       |   |   |   |   |
| Income available  to common stockholders |       | $                                | 4,350,050  |   | 9,987,551 |   | $ | 0.44 |   |

 
| ** **                               | ** ** | **Year Ended December 31, 2002** | ** ** |
|------------------------------------------|------------|----------------------------------|------------|
| ** **                               | ** ** | **Income  (Numerator)**          | ** ** | **Shares  (Denominator)** | ** ** | **Per Share  Amount** | ** ** |
| **Basic  EPS**                           |       |                             |       |   |   |   |   |
| Income available  to common stockholders |       | $                                | 749,745    |   | 9,384,097 |   | $ | 0.08 |   |
| **Effect  of Dilutive Securities**       |       |                             |       |   |   |   |   |
| Common stock  options                    |       | —                           |       | 85,633 |   | — |   |
| Restricted stock                         |       | —                           |       | 135,841 |   | — |   |
| **Diluted  EPS**                         |       |                             |       |   |   |   |   |
| Income available  to common stockholders |       | $                                | 749,745    |   | 9,605,571 |   | $ | 0.08 |   |

 

F-25

----

 

**17.****       RELATED PARTY TRANSACTIONS**

 

Thetransactions described below were carried out on terms at least as favorable tothe Company as could have been obtained from unaffiliated third parties in arm’slength negotiations, however, because the transactions were with affiliates, itis possible that the Company would have obtained different terms from a trulyunaffiliated third-party.

 

*Affiliates’Ownership in Prospects* – Edge Group Partnership, Edge HoldingCompany, L.P., a limited partnership of which Mr. Sfondrini and a corporationwholly owned by him are the general partners, Andex Energy Corporation andTexedge Energy Corporation, corporations of which Mr. Andrews is an officer andmembers of his immediate family hold ownership interests, Mr. Raphael, Jovin,L.P. (a limited partnership, the general partners of which are a company whollyowned by Mr. Sfondrini and a company of which Mr. Andrews is an officer) andEssex II Joint Venture, own certain working interests in the Company’s Nita andAustin Prospects and certain other wells and prospects operated by the Company.These working interests aggregate 7.19% in the Austin Prospect, 6.27% in theNita Prospect and are neglible in other wells and prospects. These workinginterests bear their share of lease operating costs and royalty burdens on thesame basis as the Company. In addition, Bamaedge, L.P., a limited partnershipof which Andex Energy Corporation is the general partner, and Mr. Raphael alsohold overriding royalty interests with respect to the Company’s workinginterest in certain wells and prospects. Neither Mr. Raphael nor Bamaedge L.P. has an overriding interest inexcess of 0.075% in any one well or prospect. Essex I Joint Venture and EssexII Joint Venture (a joint venture of which Mr. Sfondrini and a company whollyowned by him are the managers) own royalty and overriding royalty interests invarious wells operated by the Company. The combined royalty and overridingroyalty interests of the Essex I and Essex II Joint Ventures do not exceed 6.2%in any one well or prospect. The gross amounts paid or accrued to these personsand entities by the Company in 2004 (including net revenue, royalty andoverriding royalty interests) and the amounts these same persons and entitiespaid to the Company for their respective share of lease operating expenses andother costs is set forth in the following table:

 
| **Owner**                               | ** ** | **Total Amounts  Paid by the  Company to  Owners in 2004  including  Overriding  Royalty (1)** | ** ** | **Lease  Operating  Expenses  paid to the  Company by  Owners in  2004** | ** ** |
|-----------------------------------------|------------|------------------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------------|------------|
| Andex  Corporation /Texedge Corporation |       | $                                                                                              | 3,896      |                                                                     | $          | 2,578 |   |
| Bamaedge, L.P.                          |       | 3,594                                                                                          |       | —                                                                   |       |
| Edge Group  Partnership                 |       | 387,603                                                                                        |       | 40,284                                                                   |       |
| Edge Holding  Co., L.P.                 |       | 71,177                                                                                         |       | 7,065                                                                    |       |
| Essex I Royalty  Joint Venture          |       | 32,603                                                                                         |       | —                                                                   |       |
| Essex II Royalty  Joint Venture         |       | 150,509                                                                                        |       | 5,629                                                                    |       |
| Jovin, L.P.                             |       | —                                                                                         |       | —                                                                   |       |
| Stanley Raphael                         |       | 5,209                                                                                          |       | 412                                                                      |       |
| **Total**                               |       | $                                                                                              | 654,591    |                                                                     | $          | 55,968 |   |

 

----

(1)          In the case of Essex Iand II Royalty Joint Ventures, amount includes royalty income in addition toworking interest and overriding royalty income. The Company sold its interestin these entities in 2003, but Mr. Sfondrini, a Director, maintains an indirectinterest in these entities.

 

**18.****       SUPPLEMENTAL DISCLOSURE OFNON-CASH INVESTING AND FINANCING ACTIVITIES**

 

A summary of non-cashinvesting and financing activities for the years ended December 31, 2004, 2003and 2002 is presented below:

 

F-26

----

 
| **Description**                                                                                       | ** ** | **Number  of shares  issued** | ** ** | **Fair Market  Value** | ** ** |
|-------------------------------------------------------------------------------------------------------|------------|-------------------------------|------------|------------------------|------------|
| **2004:**                                                                                             |       |                          |       |                   |       |
| Shares issued to satisfy restricted stock grants                                                      |       | 70,463                        |       | $                      | 446,881    |   |
| Shares issued to fund the Company’s matching  contribution under the Company’s 401 (k) plan |       | 7,500                         |       | $                      | 111,797    |   |
| **2003:**                                                                                             |       |                          |       |                   |       |
| Shares issued to satisfy restricted stock grants                                                      |       | 75,095                        |       | $                      | 395,192    |   |
| Shares issued to fund the Company’s matching  contribution under the Company’s 401 (k) plan |       | 14,475                        |       | $                      | 69,375     |   |
| Shares issued in Miller merger                                                                        |       | 2,604,757                     |       | $                      | 14,421,051 |   |
| **2002:**                                                                                             |       |                          |       |                   |       |
| Shares issued to satisfy restricted stock grants                                                      |       | 76,337                        |       | $                      | 409,777    |   |
| Shares issued to fund the Company’s matching  contribution under the Company’s 401 (k) plan |       | 17,538                        |       | $                      | 70,513     |   |

 

Supplemental Disclosure of Cash FlowInformation

 
| ** **                                | ** ** | **For the Year Ended December 31,** | ** ** |
|-------------------------------------------|------------|-------------------------------------|------------|
| ** **                                | ** ** | **2004**                            | ** ** | **2003** | ** ** | **2002** | ** ** |
| Cash paid during  the period for:         |       |                                |       |   |   |   |   |
| Interest, net of  amounts capitalized     |       | $                                   | 331,399    |   | $ | 678,805 |   | $ | 15,582 |   |
| Federal  alternative minimum tax payments |       | —                              |       | — |   | — |   |
|                                           |            |                                     |            |  |  |  |  |  |  |  |

 

**19.****       SUPPLEMENTALFINANCIAL QUARTERLY RESULTS (unaudited):**

                
| ** **                                                | ** **   | **Fourth  Quarter**                          | ** **   | **Restated  Third  Quarter(1)** | ** ** | **Second  Quarter** | ** ** | **First  Quarter** | ** ** |
|-----------------------------------------------------------|--------------|----------------------------------------------|--------------|---------------------------------|------------|---------------------|------------|--------------------|------------|
| *** ***                                              | *** *** | **(in thousands, except per share amounts)** | *** *** |
| **2004:**                                                 |         |                                         |         |                            |       |                |       |               |       |
| Oil and natural  gas revenue                              |         | $                                            | 19,601       |                            | $          | 13,242              |       | $                  | 15,847     |   | $ | 15,815 |   |
| Operating  expenses                                       |         | 11,293                                       |         | 9,035                           |       | 9,755               |       | 10,601             |       |
| Operating income                                          |         | 8,308                                        |         | 4,207                           |       | 6,092               |       | 5,214              |       |
| Other expense,  net                                       |         | (105                                         | )            | (50                             | )          | (142                | )          | (140               | )          |
| Income tax expense                                        |         | (2,896                                       | )            | (1,474                          | )          | (2,094              | )          | (1,791             | )          |
| Net income                                                |         | $                                            | 5,307        |                            | $          | 2,683               |       | $                  | 3,856      |   | $ | 3,283 |   |
| Basic earnings  per share                                 |         | $                                            | 0.39         |                            | $          | 0.21                |       | $                  | 0.30       |   | $ | 0.26 |   |
| Diluted earnings  per share                               |         | $                                            | 0.38         |                            | $          | 0.20                |       | $                  | 0.28       |   | $ | 0.25 |   |
|                                                      |         |                                         |         |                            |       |                |       |               |       |
| **2003:**                                                 |         |                                         |         |                            |       |                |       |               |       |
| Oil and natural  gas revenue                              |         | $                                            | 10,198       |                            | $          | 8,895               |       | $                  | 7,994      |   | $ | 6,839 |   |
| Operating  expenses                                       |         | 9,030                                        |         | 6,137                           |       | 5,453               |       | 5,205              |       |
| Operating income                                          |         | 1,168                                        |         | 2,758                           |       | 2,541               |       | 1,634              |       |
| Other expense,  net                                       |         | (206                                         | )            | (120                            | )          | (162                | )          | (174               | )          |
| Income tax  expense                                       |         | (418                                         | )            | (946                            | )          | (845                | )          | (522               | )          |
| Net income  before cumulative effect of accounting change |         | 544                                          |         | 1,692                           |       | 1,534               |       | 938                |       |
| Cumulative  effect of accounting change                   |         | —                                       |         | —                          |       | —              |       | (358               | )          |
| Net income                                                |         | $                                            | 544          |                            | $          | 1,692               |       | $                  | 1,534      |   | $ | 580 |   |
| Basic earnings  per share                                 |         | $                                            | 0.05         |                            | $          | 0.18                |       | $                  | 0.16       |   | $ | 0.06 |   |
| Diluted earnings  per share                               |         | $                                            | 0.05         |                            | $          | 0.17                |       | $                  | 0.16       |   | $ | 0.06 |   |

 

----

(1)   The Company recently discovered an error in aconsolidating financial statements spreadsheet application used to eliminateintercompany balances.  Amounts accumulatedin the property account for one subsidiary were also included as an accruedcapital expenditure by another subsidiary and inadvertently not eliminated inconsolidation.  The Company has filedAmendment No. 1 to its Quarterly Report on Form 10-Q for the quarterly periodended September 30, 2004 to restate the financial statements and otherdisclosures therein to correct such error. The amounts set forth above as of and for September 30, 2004 reflect therestated amounts.  No other interim orannual financial statements included in any other Quarterly Report on Form 10-Qor Form 10-K of the Company were required to be restated. The principal changeseffected by the restatement are set forth in the following reconciliation:

 
| ** **                   | ** **   | **Third Quarter** | ** **   | **Third Quarter** | ** **   | **Third Quarter** | ** **   |
|------------------------------|--------------|-------------------|--------------|-------------------|--------------|-------------------|--------------|
| ** **                   | ** **   | **REPORTED**      | ** **   | **ADJUSTMENTS**   | ** **   | **RESTATED**      | ** **   |
| *** ***                 | *** *** | *** ***      | *** *** | *** ***      | *** *** | *** ***      | *** *** |
| **2004**                     |         |              |         |              |         |              |         |
| Oil and natural  gas revenue |         | $                 | 13,242       |              | $            | —            |         | $ | 13,242 |   |
| Operating  expenses          |         |              |         |              |         |              |         |
|                         |         | 9,348             |         | (313              | )            | 9,035             |         |
| Operating income             |         |              |         |              |         |              |         |
|                         |         | 3,894             |         | 313               |         | 4,207             |         |
| Other expense,  net          |         |              |         |              |         |              |         |
|                         |         | (50               | )            | —            |         | (50               | )            |
| Income tax  expense          |         |              |         |              |         |              |         |
|                         |         | (1,355            | )            | (119              | )            | (1,474            | )            |
| Net income                   |         | $                 | 2,490        |              | $            | 193               |         | $ | 2,683 |   |
| Basic earnings  per share    |         | $                 | 0.19         |              | $            | 0.02              |         | $ | 0.21 |   |
| Diluted earnings  per share  |         | $                 | 0.18         |              | $            | 0.02              |         | $ | 0.20 |   |

 

 

F-27

----

 

The sum of the individual quarterly basic and dilutedearnings (loss) per share amounts may not agree with year-to-date basic anddiluted earnings (loss) per share amounts as a result of each period’scomputation being based on the weighted average number of common sharesoutstanding during that period.

 

**20.****       SUPPLEMENTARYFINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT ANDPRODUCTION ACTIVITIES (unaudited)**

 

This footnote providesunaudited information required by SFAS No. 69, “*Disclosures About Oil and Natural Gas Producing Activities*.”The Company’s oil and natural gas properties are located within the UnitedStates of America, which constitutes one cost center.

 

***CapitalizedCosts -***Capitalized costs and accumulated depletion, depreciationand amortization relating to the Company’s oil and natural gas producingactivities, all of which are conducted within the continental United States,are summarized below:

 
| ** **                                            | ** ** | **December 31,** | ** **  |
|-------------------------------------------------------|------------|------------------|-------------|
| ** **                                            | ** ** | **2004**         | ** **  | **2003** | ** ** |
| ** **                                            | ** ** | ** **       | ** **  | ** ** | ** ** |
| Developed oil  and natural gas properties             |       | $                | 243,187,690 |   | $ | 164,419,619 |   |
| Unevaluated oil  and natural gas properties           |       | 15,490,704       |        | 5,044,584 |   |
| Accumulated  depletion, depreciation and amortization |       | (93,639,018      | )           | (72,167,411 | ) |
| Net capitalized  cost                                 |       | $                | 165,039,376 |   | $ | 97,296,792 |   |

 

***CostsIncurred******-***Costs****incurred inoil and natural gas property acquisition, exploration and developmentactivities are summarized below:

 
| ** **                  | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------|------------|-----------------------------|------------|
| ** **                  | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| Acquisition  cost:          |       |                        |       |   |   |   |   |
| Unproved properties         |       | $                           | 12,162,649 |   | $ | 6,052,137 |   | $ | 5,465,794 |   |
| Proved  properties          |       | 33,980,135                  |       | 10,373,529 |   | 1,369,464 |   |
| Exploration  costs          |       | 8,297,370                   |       | 6,016,951 |   | 4,725,032 |   |
| Development  costs          |       | 34,548,410                  |       | 12,271,471 |   | 7,926,579 |   |
| Subtotal                    |       | 88,988,564                  |       | 34,714,088 |   | 19,486,869 |   |
| Asset retirement  costs (1) |       | 278,125                     |       | 897,512 |   | — |   |
|                        |       |                        |       |   |   |   |   |
| Total costs  incurred       |       | $                           | 89,266,689 |   | $ | 35,611,600 |   | $ | 19,486,869 |   |

 

----

(1)          Excluded from assetretirement costs in 2003 was $640,400 related to the cumulative effect of theadoption of SFAS No. 143 on January 1, 2003 (See Note 7).

 

Net costs incurred excludes sales of proved oil andnatural gas properties which are accounted for as adjustments of capitalizedcosts with no gain or loss recognized, unless such adjustments would significantlyalter the relationship between capitalized costs and proved reserves.

 

***Resultsof Operations -*** Results of operations for the Company’soil and natural gas producing activities are summarized below:

 
| ** **                                                   | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                   | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| Oil and natural  gas revenue                                 |       | $                           | 64,505,348 |   | $ | 33,926,007 |   | $ | 20,911,294 |   |
| Operating  expenses:                                         |       |                        |       |   |   |   |   |
| Oil and natural  gas operating expenses and ad valorem taxes |       | 5,356,246                   |       | 3,109,392 |   | 2,628,320 |   |
| Production taxes                                             |       | 3,952,524                   |       | 2,006,402 |   | 1,203,270 |   |
| Accretion  expense (1)                                       |       | 98,968                      |       | 66,625 |   | — |   |
| Depletion  expense                                           |       | 21,471,606                  |       | 12,906,956 |   | 9,697,144 |   |
| Results of  operations from oil and gas producing activities |       | $                           | 33,626,004 |   | $ | 15,836,632 |   | $ | 7,382,560 |   |

 

F-28

----

 

----

(1)          The Company adopted SFAS No. 143 effective January 1, 2003 using acumulative effect approach, therefore no comparable accretion expense appears2002 (See Note 7).

 

***Reserves-***Proved reserves are estimated quantities of oil andnatural gas, which geological and engineering data demonstrate with reasonablecertainty to be, recoverable in future years from known reservoirs underexisting economic and operating conditions. Proved developed reserves are proved reserves that can reasonably beexpected to be recovered through existing wells with existing equipment andoperating methods.  Proved oil andnatural gas reserve quantities and the related discounted future net cash flowsbefore income taxes (see Standardized Measure) for the periods presented arebased on estimates prepared by Ryder Scott Company and W.D. Von Gonten &Co., independent petroleum engineers. Such estimates have been prepared in accordance with guidelinesestablished by the SEC.

 

The Company’s netownership in estimated quantities of proved oil and natural gas reserves andchanges in net proved reserves, all of which are located in the continentalUnited States, are summarized below.

 
| ** **                                 | ** ** | **Natural Gas  (Mcf)  Year Ended December 31,** | ** ** |
|--------------------------------------------|------------|-------------------------------------------------|------------|
| ** **                                 | ** ** | **2004**                                        | ** ** | **2003** | ** ** | **2002** | ** ** |
| Proved developed  and undeveloped reserves |       |                                            |       |   |   |   |   |
| Beginning of  year                         |       | 46,824,000                                      |       | 34,980,000 |   | 38,934,000 |   |
| Revisions of  previous estimates           |       | (5,993,260                                      | )          | (486,143 | ) | (5,579,800 | ) |
| Purchase of oil  and gas properties        |       | 14,803,000                                      |       | 8,437,000 |   | 521,300 |   |
| Extensions and  discoveries                |       | 19,825,551                                      |       | 10,248,298 |   | 6,376,900 |   |
| Sales of natural  gas properties           |       | —                                          |       | (65,100 | ) | (6,000 | ) |
| Production                                 |       | (9,148,191                                      | )          | (6,290,055 | ) | (5,266,400 | ) |
| End of year                                |       | 66,311,100                                      |       | 46,824,000 |   | 34,980,000 |   |
|                                       |       |                                            |       |   |   |   |   |
| Proved developed  reserves at year end     |       | 50,698,000                                      |       | 36,938,000 |   | 24,234,000 |   |

 
| ** **                                 | ** ** | **Oil, Condensate and Natural Gas Liquids  (Bbls)  Year Ended December 31,** | ** ** |
|--------------------------------------------|------------|------------------------------------------------------------------------------|------------|
| ** **                                 | ** ** | **2004**                                                                     | ** ** | **2003** | ** ** | **2002** | ** ** |
| Proved developed  and undeveloped reserves |       |                                                                         |       |   |   |   |   |
| Beginning of  year                         |       | 2,851,072                                                                    |       | 2,342,315 |   | 978,361 |   |
| Revisions of  previous estimates           |       | (106,133                                                                     | )          | (46,348 | ) | 1,090,845 |   |
| Purchase of oil  and gas properties        |       | 267,354                                                                      |       | 387,743 |   | 62,939 |   |
| Extensions and  discoveries                |       | 1,270,134                                                                    |       | 472,904 |   | 491,519 |   |
| Sales of natural  gas properties           |       | —                                                                       |       | (5,058 | ) | (521 | ) |
| Production                                 |       | (490,801                                                                     | )          | (300,484 | ) | (280,828 | ) |
| End of year                                |       | 3,791,626                                                                    |       | 2,851,072 |   | 2,342,315 |   |
|                                       |       |                                                                         |       |   |   |   |   |
| Proved developed  reserves at year end     |       | 2,698,125                                                                    |       | 2,104,610 |   | 1,509,950 |   |

 

***StandardizedMeasure -***The******StandardizedMeasure of Discounted Future Net Cash Flows relating to the Company’s ownershipinterests in proved oil and natural gas reserves for each of the three yearsended December 31, 2004 is shown below:

 

 
| ** **                                                | ** ** | **Year Ended December 31,** | ** **  |
|-----------------------------------------------------------|------------|-----------------------------|-------------|
| ** **                                                | ** ** | **2004**                    | ** **  | **2003** | ** ** | **2002** | ** ** |
|                                                      |       |                        |        |   |   |   |   |
| Future cash  inflows                                      |       | $                           | 521,262,763 |   | $ | 350,187,406 |   | $ | 212,064,453 |   |
| Future oil and  natural gas operating expenses            |       | (118,492,193                | )           | (75,208,036 | ) | (33,151,831 | ) |
| Future  development costs                                 |       | (31,794,903                 | )           | (13,203,914 | ) | (8,069,700 | ) |
| Future income  tax expense                                |       | (75,094,884                 | )           | (53,902,855 | ) | (36,475,435 | ) |
| Future net cash  flows                                    |       | 295,880,783                 |        | 207,872,601 |   | 134,367,487 |   |
| 10% discount  factor                                      |       | (79,009,770                 | )           | (55,705,257 | ) | (36,811,015 | ) |
| Standardized  measure of discounted future net cash flows |       | $                           | 216,871,013 |   | $ | 152,167,344 |   | $ | 97,556,472 |   |

 

F-29

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Future cash flows arecomputed by applying year-end prices of oil and natural gas to year-endquantities of proved oil and natural gas reserves.  Future oil and natural gas operating expensesand development costs are computed primarily by the Company’s internalpetroleum engineers and are provided to external independent petroleumengineers as estimates of expenditures to be incurred in developing andproducing the Company’s proved oil and natural gas reserves at the end of theyear, based on year-end costs and assuming the continuation of existingeconomic conditions.

 

Future income taxes arebased on year-end statutory rates, adjusted for net operating losscarryforwards and tax credits.  Adiscount factor of 10% was used to reflect the timing of future net cashflows.  The Standardized Measure ofDiscounted Future Net Cash Flows is not intended to represent the replacementcost or fair market value of the Company’s oil and natural gas properties.

 

The Standardized Measureof Discounted Future Net Cash Flows does not purport, nor should it beinterpreted, to present the fair value of the Company’s oil and natural gasreserves.  An estimate of fair valuewould also take into account, among other things, the recovery of reserves notpresently classified as proved, anticipated future changes in prices and costs,a discount factor more representative of the time value of money and the risksinherent in reserve estimates.

 

***Changesin Standardized Measure -***Changes in StandardizedMeasure of Discounted Future Net Cash Flows relating to proved oil and gasreserves are summarized below:

 
| ** **                                                                   | ** ** | **Year Ended December 31,** | ** **  |
|------------------------------------------------------------------------------|------------|-----------------------------|-------------|
| ** **                                                                   | ** ** | **2004**                    | ** **  | **2003** | ** ** | **2002** | ** ** |
| Changes due to  current year operations:                                     |       |                        |        |   |   |   |   |
| Sales of oil and  natural gas, net of oil and natural gas operating expenses |       | $                           | (56,968,998 | ) | $ | (33,393,818 | ) | $ | (17,079,705 | ) |
| Sales of oil and  natural gas properties                                     |       | —                      |        | (356,195 | ) | (5,629 | ) |
| Purchase of oil  and gas properties                                          |       | 65,402,748                  |        | 28,079,806 |   | 1,402,730 |   |
| Extensions and  discoveries                                                  |       | 65,466,396                  |        | 33,535,443 |   | 15,519,251 |   |
| Changes due to  revisions of standardized variables:                         |       |                        |        |   |   |   |   |
| Prices and  operating expenses                                               |       | 17,648,293                  |        | 32,213,734 |   | 38,029,737 |   |
| Revisions of  previous quantity estimates                                    |       | (21,190,007                 | )           | (2,395,449 | ) | 2,378,838 |   |
| Estimated future  development costs                                          |       | (15,961,730                 | )           | (2,295,084 | ) | (20,172 | ) |
| Income taxes                                                                 |       | (9,189,919                  | )           | (7,585,409 | ) | (11,143,442 | ) |
| Accretion of  discount                                                       |       | 15,216,734                  |        | 9,755,647 |   | 6,328,285 |   |
| Production rates  (timing) and other                                         |       | 4,280,152                   |        | (2,947,803 | ) | (1,136,268 | ) |
| Net change                                                                   |       | 64,703,669                  |        | 54,610,872 |   | 34,273,625 |   |
| Beginning of  year                                                           |       | 152,167,344                 |        | 97,556,472 |   | 63,282,847 |   |
| End of year                                                                  |       | $                           | 216,871,013 |   | $ | 152,167,344 |   | $ | 97,556,472 |   |

 

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

 

F-30

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# **INDEX TO EXHIBITS**

 
| **Exhibit No.** | ** ** | ** ** | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
|-----------------|------------|------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| 2.1             |       | —     |       | Amended and Restated  Combination Agreement by and among (i) Edge Group II Limited Partnership,  (ii) Gulfedge Limited Partnership, (iii) Edge Group Partnership, (iv) Edge  Petroleum Corporation, (v) Edge Mergeco, Inc. and (vi) the Company,  dated as of January 13, 1997 (Incorporated by reference from exhibit 2.1  to the Company’s Registration Statement on Form S-4 (Registration No.  333-17269)).                                                                                  |
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| 2.2             |       | —     |       | Agreement and Plan of  Merger dated as of May 28, 2003 among Edge Petroleum Corporation, Edge  Delaware Sub Inc. and Miller Exploration Company (Miller”) (Incorporated by  reference from Annex A to the Joint Proxy Statement/Prospectus contained in  the Company’s Registration Statement on Form S-4/A filed on October 31, 2003  (Registration No. 333-106484)).                                                                                                                                |
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| 2.3             |       | —     |       | Asset Purchase  Agreement by and among Contango STEP, L.P., Contango Oil & Gas Company,  Edge Petroleum Exploration Company and Edge Petroleum Corporation dated  October 7, 2004 (Incorporated by reference from exhibit 2.1 to the Company’s  Current Report on Form 8-K filed October 12, 2004).                                                                                                                                                                                                    |
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| 3.1             |       | —     |       | Restated Certificate of  Incorporation of the Company (Incorporated by reference from exhibit 3.1 to  the Company’s Registration Statement on Form S-1/A filed on February 5, 1997  (Registration No. 333-17267)).                                                                                                                                                                                                                                                                                         |
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| 3.2             |       | —     |       | Certificate of  Amendment to the Restated Certificate of Incorporation of the Company  (Incorporated by reference from exhibit 3.1 to the Company’s Registration  Statement on Form S-1/A filed on February 5, 1997 (Registration No.  333-17267)).                                                                                                                                                                                                                                                        |
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| 3.3             |       | —     |       | 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).                                                                                                                                                                                                                                                                                                                                     |
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| 3.4             |       | —     |       | First Amendment to  Bylaws of the Company on September 28, 1999 (Incorporated by Reference from  exhibit 3.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly  period ended March 31, 2003).                                                                                                                                                                                                                                                                                               |
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| 3.5             |       | —     |       | Second Amendment to  Bylaws of the Company on May 7, 2003 (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             |       | —     |       | Third Amended and  Restated Credit Agreement dated December 31, 2003 among Edge Petroleum  Corporation, Edge Petroleum Exploration Company, Edge Petroleum Operating  Company, Inc., Miller Oil Corporation, and Miller Exploration Company, as borrowers,  the lenders thereto and Union Bank of California, N.A., a national banking  association, as Agent (Incorporated by reference from Exhibit 4.1 to the  Company’s Quarterly Report on Form 10-Q for the quarterly period ended March  31, 2004). |
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| 4.2             |       | —     |       | 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).                                                                                                                                                                                                                                                |
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| 4.3             |       | —     |       | Registration Rights  Agreement by and among Edge Petroleum Corporation, Guardian Energy Management  Corp., Kelly E. Miller and the Debra A. Miller Trust, dated December 4, 2003  (Incorporated by reference from exhibit 4.2 to the Company’s Registration  Statement on Form S-3 filed on February 3, 2004 (Registration No.  333-112462)).                                                                                                                                                              |

 

F-31

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| 4.4        |   | — |   | Miller Exploration  Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by  reference from exhibit 10.1(a) to Miller Exploration Company’s Annual Report  on Form 10-K for the year ended December 31, 1997 (File No. 000-23431)).                                                                               |
|------------|--------|--------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| 4.5        |   | — |   | Amendment No. 1 to the  Miller Exploration Company Stock Option and Restricted Stock Plan of 1997  (Incorporated by reference to Exhibit 4.2 from Miller Exploration Company’s  Registration Statement on Form S-8 filed on April 11, 2001 (Registration No.  333-58678)).                                                        |
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| 4.6        |   | — |   | Amendment No. 2 to the  Miller Exploration Company Stock Option and Restricted Stock Plan of 1997  (Incorporated by reference from Exhibit 4.3 to Miller Exploration Company’s  Registration Statement on Form S-8 filed on April 11, 2001 (Registration No.  333-58678)).                                                        |
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| 4.7        |   | — |   | Form of Miller Stock  Option Agreement (Incorporated by reference from exhibit 10.1(b) to Miller  Exploration Company’s Annual Report on Form 10-K for the year ended December  31, 1997 (File No. 000-23431)).                                                                                                                   |
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| †10.1 |   | — |   | Form of Indemnification  Agreement between the Company and each of its directors (Incorporated by  reference from exhibit 10.7 to the Company’s Registration Statement on Form  S-4 (Registration No. 333-17269)).                                                                                                                |
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| †10.2 |   | — |   | Stock Option Plan of  Edge Petroleum Corporation, a Texas corporation (Incorporated by reference  from exhibit 10.13 to the Company’s Registration Statement on Form S-4  (Registration No. 333-17269)).                                                                                                                          |
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| †10.3 |   | — |   | Employment Agreement  dated as of November 16, 1998, by and between the Company and John W. Elias  (Incorporated by reference from 10.12 to the Company’s Annual Report on Form  10-K for the year ended December 31, 1998).                                                                                                      |
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| †10.4 |   | — |   | Incentive Plan of Edge  Petroleum Corporation as Amended and Restated Effective as of June 1, 2004  (Incorporated by reference from exhibit 10.9 to the Company’s Quarterly  Report on Form 10-Q for the quarterly period ended June 30, 2004).                                                                                   |
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| †10.5 |   | — |   | Edge Petroleum  Corporation Incentive Plan “Standard Non-Qualified Stock Option Agreement” by  and between Edge Petroleum Corporation and the Officers named therein  (Incorporated by reference from exhibit 10.2 to the Company’s Quarterly  Report on Form 10-Q for the quarterly period ended September 30, 1999).  |
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| †10.6 |   | — |   | Edge Petroleum  Corporation Incentive Plan “Director Non-Qualified Stock Option Agreement” by  and between Edge Petroleum Corporation and the Directors named therein  (Incorporated by reference from exhibit 10.3 to the Company’s Quarterly  Report on Form 10-Q for the quarterly period ended September 30, 1999). |
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| †10.7 |   | — |   | Severance Agreements by  and between Edge Petroleum Corporation and the Officers of the Company named  herein (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).                                                                   |
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| †10.8 |   | — |   | Form of Director’s  Restricted Stock Award Agreement under the Incentive Plan of Edge Petroleum  Corporation (Incorporated by reference from exhibit 10.12 to the Company’s  Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004).                                                                    |
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| †10.9 |   | — |   | 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).                                                                       |

 

F-32

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| †10.10         |   | — |   | 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)).           |
|---------------------|--------|--------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                |   |   |   |                                                                                                                                                                                                                                            |
| †10.11         |   | — |   | Form of Edge Petroleum  Corporation John W. Elias Non-Qualified Stock Option Agreement (Incorporated  by reference from exhibit 4.6 to the Company’s Registration Statement on Form  S-8 filed May 30, 2001 (Registration No. 333-61890)). |
|                |   |   |   |                                                                                                                                                                                                                                            |
| *†10.12 – |   |   |   | Summary of  Compensation of Non-Employee Directors.                                                                                                                                                                                             |
|                |   |   |   |                                                                                                                                                                                                                                            |
| *†10.13 – |   |   |   | Salaries and Other  Compensation of Executive Officers.                                                                                                                                                                                         |
|                |   |   |   |                                                                                                                                                                                                                                            |
| *†10.14 – |   |   |   | Description of 2004  Bonus Program for Executive Officers.                                                                                                                                                                                      |
|                |   |   |   |                                                                                                                                                                                                                                            |
| *21.1               |   | — |   | Subsidiaries of the  Company.                                                                                                                                                                                                                   |
|                |   |   |   |                                                                                                                                                                                                                                            |
| *23.1               |   | — |   | Consent of BDO Seidman,  LLP.                                                                                                                                                                                                                   |
|                |   |   |   |                                                                                                                                                                                                                                            |
| *23.2               |   | — |   | Consent of Ryder Scott  Company.                                                                                                                                                                                                                |
|                |   |   |   |                                                                                                                                                                                                                                            |
| *23.3               |   | — |   | Consent of W.D. Von  Gonten & Co.                                                                                                                                                                                                           |
|                |   |   |   |                                                                                                                                                                                                                                            |
| *31.1               |   | — |   | Certification by John  W. Elias, Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a)  under the Securities Exchange Act of 1934.                                                                                              |
|                |   |   |   |                                                                                                                                                                                                                                            |
| *31.2               |   | — |   | Certification by  Michael G. Long , Chief Financial and Accounting Officer, pursuant to Rule  13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.                                                                            |
|                |   |   |   |                                                                                                                                                                                                                                            |
| *32.1               |   | — |   | Certification by John  W. Elias, Chief Executive Officer, pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter  63 of Title 18, United States Code).                                    |
|                |   |   |   |                                                                                                                                                                                                                                            |
| *32.2               |   | — |   | Certification by  Michael G. Long, Chief Financial and Accounting Officer, pursuant to Section  906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section  1350, Chapter 63 of Title 18, United States Code).                   |
|                |   |   |   |                                                                                                                                                                                                                                            |
| *99.1               |   | — |   | Summary of Reserve  Report of Ryder Scott Company Petroleum Engineers as of December 31, 2004.                                                                                                                                                  |
|                |   |   |   |                                                                                                                                                                                                                                            |
| *99.2               |   | — |   | Summary of Reserve  Report of W. D. Von Gonten & Co. Petroleum Engineers as of December 31,  2004.                                                                                                                                          |

 

----

* Filed herewith.

†Denotes management or compensatory contract, arrangement or agreement.

 

F-33

----