** **

**UNITED STATES SECURITIES AND EXCHANGE COMMISSION**

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

#  

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

 
| **ý**                                      | ** ** | **ANNUAL  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE  ACT OF 1934**     |
|-------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------|
|                                            |       |                                                                                                     |
| **For the fiscal year ended December 31, 2005** |
|                                            |       |                                                                                                     |
| **OR**                                          |
|                                            |       |                                                                                                     |
| **o**                                           | ** ** | **TRANSITION  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE  ACT OF 1934** |

 

##### **For the transitionperiod from         to         **

#####  

**Commission file number:  0-22149**

 

#### **EDGE PETROLEUM CORPORATION**

(Exact name of Registrant as specified in itscharter)

 

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

 

**713-654-8960**

(Registrant’s telephone number, includingarea code)

 

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Securities registered pursuant to Section 12(b) ofthe Act:

**None**

 

Securities registered pursuant to Section 12(g) ofthe Act:

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

 

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

 

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

 

Indicateby check mark whether the registrant (1) has filed all reports required tobe filed by Section 13 or 15(d) of the Securities Exchange Act of1934 during the preceding 12 months (or for such shorter period that theregistrant was required to file such reports), and (2) has been subject tosuch filing requirements for the past 90 days.  ý Yes o No

 

Indicateby check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K (§229.405 of this chapter) is not contained herein, and will notbe contained, to the best of registrant’s knowledge, in definitive proxy orinformation statements incorporated by reference in Part III of this Form 10-Kor any amendment to this Form 10-K.              o

 

Indicateby check mark whether the registrant is a large accelerated filer, anaccelerated filed, or a non-accelerated filer. See definition of “acceleratedfiler and larger accelerated filer” in Rule 12b-2 of the Exchange Act.:
| o Large accelerated filer |   | ýAccelerated Filer |   | o Non-accelerated filer |
|---------------------------|--------|-------------------------|--------|-------------------------|

 

Indicateby check mark whether the registrant is a shell company (as defined in Rule 12b-2of the Exchange Act). oYes ýNo

 

As of June 30, 2005, the aggregate market value of the votingstock held by non-affiliates of the registrant was $258.2 million (based on avalue of $15.62 per share, the closing price of the Common Stock as quoted byNASDAQ National Market on such date).

 

Asof March 10, 2006, 17,239,679 shares of Common Stock, par value $.01 pershare, were outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

***Portions ofthe definitive proxy statement for the registrant’s 2006 Annual Meeting ofShareholders, to be filed pursuant to Regulation 14A under the SecuritiesExchange Act of 1934, are incorporated by reference into Part III of thisreport.***

 

 

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***TABLE OF CONTENTS***

 
| *** ***         | ***PART I***                                                                                                         | *** *** |
|----------------------|---------------------------------------------------------------------------------------------------------------------------|--------------|
| *** ***         | *** ***                                                                                                              | *** *** |
| ***ITEMS 1 AND 2.*** | ***BUSINESS AND PROPERTIES***                                                                                             | *** *** |
| ***ITEM 1A.***       | ***RISK  FACTORS***                                                                                                       | *** *** |
| ***ITEM  1B.***      | ***UNRESOLVED  STAFF COMMENTS***                                                                                          | *** *** |
| ***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 OPERATION***                          | *** *** |
| ***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  ACCOUNTING FEES AND SERVICES***                                                                             | *** *** |
| *** ***         | *** ***                                                                                                              | *** *** |
| *** ***         | ***PART IV***                                                                                                        | *** *** |
| *** ***         | *** ***                                                                                                              | *** *** |
| ***ITEM 15.***       | ***EXHIBITS AND  FINANCIAL STATEMENT SCHEDULES***                                                                         | *** *** |

 

2

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

#####  

*Unless otherwise indicated by the context, references herein to the “Company”,“Edge”, “we”, “our” or “us” mean Edge Petroleum Corporation, a Delawarecorporation, and its corporate and partnership subsidiaries and predecessors. Certainterms used herein relating to the oil and natural gas industry are defined inITEMS 1 AND 2. “BUSINESS AND PROPERTIES**–*CERTAINDEFINITIONS.*”*

 

**FORWARD LOOKING INFORMATION**

 

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 and administrativeexpenses on a per unit of production basis, changes in wells operated andreserves, future growth and expansion, future exploration, future seismic data(including timing and results), expansion of operation, our ability to generateadditional prospects, review of outside generated prospects and acquisitions,additional reserves and reserve increases, replace production and manage ourasset base, enhancement of visualization and interpretation strengths,expansion and improvement of capabilities, integration of new technology intooperations, credit facilities, redetermination of our borrowing base,attraction of new members to the technical team, future compensation programs,new focus on core areas, new prospects and drilling locations, new alliances,future capital expenditures (or funding thereof) and working capital,sufficiency of future working capital, borrowings and capital resources 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, the impact of any change in accountingpolicies on our financial statements, the number, timing or results of anywells, the plans for timing, interpretation and results of new or existingseismic surveys or seismic data, future production or reserves, futureacquisition of leases, lease options or other land rights, any other statementsregarding future operations, financial results, opportunities, growth, businessplans and strategy and other statements that are not historical facts areforward-looking statements. These forward-looking statements reflect ourcurrent view of future events and financial performance. When used in thisdocument, the words “budgeted,” “anticipate,” “estimate,” “expect,” “may,” “project,”“believe,” “intend,” “plan,” “potential,” “forecast,” “might,” “predict,” “should”and similar expressions are intended to be among the expressions that identifyforward-looking statements. These forward-looking statements speak only as oftheir dates and should not be unduly relied upon. We undertake no obligation topublicly update or revise any forward-looking statement, whether as a result ofnew information, future events, or otherwise. Such statements involve risks anduncertainties, including, but not limited to, those set forth under *ITEM 1A. “**RISK FACTORS”* and other factors detailed inthis document and our other filings with the Securities and Exchange Commission.Should one or more of these risks or uncertainties materialize, or shouldunderlying assumptions prove incorrect, actual outcomes may varymaterially from those indicated. All subsequent written and oral forward-lookingstatements attributable to us or to persons acting on our behalf are expresslyqualified in their entirety by reference to these risks and uncertainties.

 

**AVAILABLE INFORMATION**

 

Our website address is www.edgepet.com. We make ourwebsite content available for information purposes only. It should not berelied upon for investment purposes, nor is it incorporated by reference inthis Form 10-K. We make available on this website under “Investor Relations- SEC Filings,” free of charge, our annual reports on Form 10-K, quarterlyreports on Form 10-Q, current reports on Form 8-K and amendments tothose reports as soon as reasonably practicable after we electronically filethose materials with, or furnish those materials to, the Securities andExchange Commission (“SEC”). The SEC also maintains a website at www.sec.govthat contains reports, proxy statements and other information regarding SECregistrants, including us.

 

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**PART I**

 

***ITEMS 1 AND 2. BUSINESS AND PROPERTIES***

 

###### **Overview**

######  

Edge Petroleum Corporation is an independent oil andnatural gas company engaged in the exploration, development, acquisition andproduction of crude oil and natural gas properties in the United States. Edgewas founded in 1983 as a private company and went public in 1997. We haveevolved over time from a prospect generation organization focused on high-risk,high-reward exploration projects to a team-driven organization focused on abalanced program of exploration, exploitation, development and acquisition of oiland natural gas properties. Following a top-level management change in late1998, a more disciplined style of business planning and management wasintegrated into our technology-driven drilling activities. We believe thecontinuation of this disciplined business model has resulted in continuedgrowth in reserves, production and financial strength and flexibility.

 

# **RecentDevelopments & Accomplishments**

#  

At year-end 2005, our net proved reserves were 102.8 Bcfe, comprised of82.3 billion cubic feet of natural gas, 1.2 million barrels of natural gasliquids and 2.2 million barrels of crude oil and condensate. Natural gas andnatural gas liquids accounted for approximately 87% of those proved reserves. Approximately74% of total proved reserves were developed as of year-end 2005 and they wereall located onshore, in the United States. We spent much of 2005 (i) developingand exploiting assets acquired late in 2004, (ii) developing those assetsin our southeast New Mexico exploration alliance entered into late in 2003, and(iii) developing our remaining core asset base. On February 14, 2005,we announced that we had entered into a new exploration and development ventureto jointly explore for oil and natural gas in south Texas with a private oiland gas company. This venture is called the “Vista Nueva” project and it gives usaccess to 3-D seismic data covering a portion of our 2004 asset acquisitionplus undeveloped acreage and an exclusive option to secure leases of unleasedminerals in the Queen City project area. Operating successes in 2005 included:

 

•                  Growing reserves to a record high for theCompany;

•                  Generating record annual revenue, net income,earnings per share and production;

•                  Drilling 65 wells withan apparent success rate of 95%;

•                  Successfully completing several acquisitions,including (i) the purchase of interests in oil and natural gas propertiesin the Chapman Ranch Field and (ii) the purchase of the stock of a privatecompany, which owned additional working interests in the Chapman Ranch Field;and

•                  Expansion of activity into the Floyd andFayettville Shale plays.

 

# **Strategy**

#  

Our business strategy is based on the following sixmain elements:

 

*1.**             **Grow reserves through thedrilling of a balanced portfolio of prospects.*We seek to maintain a prudent balance betweenhigher risk/reward wells and more moderate risk/reward wells. In 2005, wedrilled 65 wells (35.45 net), primarily in Texas, with 62 (33.20 net) of thosewells completed as productive for an apparent success rate of approximately 95%.This drilling program, along with our acquisition of certain oil and gas assetson the Chapman Ranch Field, helped us to grow our year-end proved reserves by 15%and replaced 184% of our reserves (see *“*Oiland Natural Gas Reserve Replacement”). We expect our drilling program for 2006 tobe focused primarily in south Texas, and to a lesser extent in southeastern NewMexico and Mississippi. We currently expect to drill between 55 and 60 wells (32and 35 net, respectively) in 2006 and we estimate capital spending for drillingfor the year to be approximately $98 million. In addition, we have acontingent drilling program that could add wells and costs to this estimate.Our contingent drilling program is dependent upon certain factors, includingsuccess of various related wells, commodity pricing, obtaining rigs and otherservices, obtaining certain leases and the availability of sufficient cash flowfrom operations to execute the program without materially increasing our debt.

 

*2.**             **Balance exploration riskwith the exploitation of existing properties and acquisitions that we believehave upside potential.*In2005, 64% of our reserve growth came from our drilling activity (which includesadditions, extensions 

 

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and revisions from new drilling, well work and theaddition of certain proved undeveloped locations) and the remaining 36% 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 2005 on acquisitions, and in the fourth quarter wesuccessfully closed two separate transactions related to the Chapman RanchField. We continue to work diligently to identify and evaluate acquisitionopportunities with the goal of identifying those that we believe would fit ourstrategic plan and add shareholder value.

 

We believe our core drilling program has thepotential to replace our production and to provide moderate reserve growth whileour higher-risk drilling program and acquisitions have the potential to rapidlyaccelerate our growth as well as add to future drilling opportunities.

 

*3.**             **Focus on specificgeographic areas where we believe we can add value.*We believe geographic focus is a criticalelement of success. Long-term success requires detailed knowledge of bothgeologic and geophysical attributes, as well as operating conditions in theareas in which we operate. As a result, we focus on a select number ofgeographic areas where our experience and strengths can be applied with asignificant influence on the outcome. We believe this focus will allow us tomanage a growing asset base and add value to additional properties whilecontrolling incremental costs and staffing requirements.

 

*4.**             **Integrate technologicaladvances into our exploration, drilling, production operations andadministration.*We useadvanced technologies as risk-reduction tools in our exploration, development,drilling and completion activities. Data analysis and advanced processingtechniques, combined with our more traditional sub-surface interpretationtechniques, allow our team of technical personnel to more easily identifyfeatures, structural details and fluid contacts that could be overlooked usingless sophisticated data interpretation techniques. As of December 31, 2005,we had rights to approximately 2,759 square miles of 3-D seismic dataprincipally located in Texas, Louisiana and Mississippi.

 

*5.**             **Maintain a conservativefinancial structure and control our cost structure.*We believe that a conservative financialstructure is crucial to consistent, positive financial results, management ofcyclical swings in our industry and the ability to move quickly to takeadvantage of acquisitions and attractive drilling opportunities. In order tomaximize our financial flexibility, we try to maintain a total debt-to-capitalratio of less than 30%. At December 31, 2005, our debt-to-total capitalratio was 30.7%, resulting from the use of debt to finance our acquisitionprogram in 2005. Our 2006 plans include a modest reduction of debt from excesscash flows from operating activities.

 

We try to fund most of our ongoing capitalexpenditures using cash flow from operations, reserving our debt capacity forpotential investment opportunities that we believe can profitably add to ourprogram. Part of a sound financial structure is constant attention tocosts, both operating and overhead costs. Over the past several years, we haveworked diligently to control our operating and overhead costs and instituted aformal, disciplined capital budgeting process. We strive to be creative withthe use of partnerships and alliances so as to leverage capital resources andenhance our ability to meet our objectives.

 

*6.**             **Use equity ownership andperformance based compensation programs to attract and retain a high-qualityworkforce.*Following amanagement 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 February 28, 2006, our directorsand employees, including executive officers, owned or had options to acquire anaggregate of approximately 11% of our outstanding common stock.

 

**Employees**

 

As of March 10, 2006, we had 67 full-timeemployees. We believe that our relationships with our employees are good. Noneof our employees are covered by a collective-bargaining agreement. From time totime, we utilize the services of independent consultants and contractors to perform variousprofessional services, particularly in the areas of construction, design, well-sitesurveillance, permitting and environmental assessment. Field and on-siteproduction operation services, such as pumping, maintenance, dispatching,inspection and testing are generally provided by independent contractors.

 

5

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**Offices**

 

We lease executive and corporate office space locatedin Travis Tower in Houston, Texas.

 

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

 

The following table sets forth our estimated netproved oil and natural gas reserves and the present value of estimated futurepretax net cash flows related to such reserves as of December 31, 2005. Weengaged 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 proved reserves, and thepresent value of such estimated future net revenue as of December 31, 2005.Ryder Scott and WDVG’s estimates were based upon a review of productionhistories and other geologic, economic, ownership and engineering data providedby us. Ryder Scott has independently evaluated our reserves for the past twelveyears and WDVG has independently reviewed the reserves we acquired fromContango late in 2004 for the past four years. In estimating the reserve quantitiesthat are economically recoverable, Ryder Scott and WDVG used year-end oil andnatural gas prices in effect at December 31, 2005 and estimateddevelopment and production costs that were in effect during December 2005without giving effect to hedging activities. In accordance with SEC regulations,no price or cost escalation or reduction was considered by Ryder Scott and WDVG.For further information concerning Ryder Scott and WDVG’s estimates of our provedreserves at December 31, 2005, see the summaries of the reserve reports ofRyder Scott and WDVG included as exhibits to this Form 10-K (respectively, the “RyderScott Report” and the “WDVG Report”). In accordance with Statement of FinancialAccounting Standards (“SFAS”) No. 69, *DisclosuresAbout Oil and Natural Gas Producing Activities,* the present value ofestimated future net revenues before income taxes was prepared using constantprices as of the calculation date, discounted at 10% per annum on a pretaxbasis, and is not intended to represent the current market value of theestimated oil and natural gas reserves owned by us. For further informationconcerning the present value of future net revenue from these proved reserves,see Note 20 to our consolidated financial statements. See *ITEM 1A. “RISK FACTORS.”*  The oil and natural gas reserve data includedin or incorporated by reference in this document are only estimates and may proveto be inaccurate.

 
| ** **                                                                                     | ** ** | **Proved Reserves as of December 31, 2005** | ** **  |
|------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------|-------------|
| ** **                                                                                     | ** ** | **Developed (1)**                                                    | ** **  | **Undeveloped (2)** | ** ** | **Total** | ** ** |
|                                                                                           |       |                                                                      |        |   |   |   |   |
| Oil and  condensate (MBbls)(3)                                                                 |       | 2,852                                                                     |        | 558 |   | 3,410 |   |
| Natural gas  (MMcf)                                                                            |       | 59,066                                                                    |        | 23,224 |   | 82,290 |   |
| Total Mmcfe                                                                                    |       | 76,177                                                                    |        | 26,576 |   | 102,753 |   |
|                                                                                           |       |                                                                      |        |   |   |   |   |
| Estimated  future net revenue before income taxes                                              |       | $                                                                         | 535,246,303 |   | $ | 142,304,637 |   | $ | 677,550,940 |   |
|                                                                                           |       |                                                                      |        |   |   |   |   |
| Present  value of estimated future net revenue before income taxes (discounted 10%  annum) (4) |       | $                                                                         | 365,438,181 |   | $ | 89,454,019 |   | $ | 454,892,200 |   |
| Future  income taxes (discounted 10% annum)                                                    |       | (87,387,800                                                               | )           | (23,714,851 | ) | (111,102,651 | ) |
| Standardized  measure of discounted future net cash flows                                      |       | $                                                                         | 278,050,381 |   | $ | 65,739,168 |   | $ | 343,789,549 |   |

 

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(1)          Proved developed reserves are proved reservesthat are expected to be recovered from existing wells with existing equipmentand operating methods.

(2)          Proved undeveloped reserves are provedreserves which are expected to be recovered from new wells on undrilled acreageor from existing wells where a relatively major expenditure is required forrecompletion.

(3)          Includes natural gas liquids.

(4)          Estimated future net revenue representsestimated future gross revenue to be generated from the production of provedreserves, net of estimated future production and development costs, usingyear-end NYMEX oil and natural gas prices in effect at December 31, 2005,which were $10.05 per MMbtu of natural gas and $61.04 per Bbl of oil.Management believes that the presentation of the present value of future netcash flows attributable to estimated proved reserves, discounted at 10% perannum (the “PV-10 Value”), may be considered a non-GAAP financial measureas defined in Item 10(e) of Regulation S-K, therefore the Company hasincluded this reconciliation of the measure to the most directly comparableGAAP financial measure (Standardized measure of discounted future net cash flows).Management believes that the presentation of PV-10 Value provides usefulinformation to investors because it is widely used by professional analysts andsophisticated investors in evaluating oil and gas companies. Because manyfactors that are unique to each individual company may impact the amountof future income taxes to be paid, the use of the pre-tax measure providesgreater comparability 

 

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when evaluating companies. It is relevant and useful to investors forevaluating the relative monetary significance of the Company’s oil and naturalgas properties. Further, investors may utilize the measure as a basis forcomparison of the relative size and value of the Company’s reserves to othercompanies. Management also uses this pre-tax measure when assessing thepotential return on investment related to its oil and natural gas propertiesand in evaluating acquisition candidates. The PV-10 Value is not a measure offinancial or operating performance under GAAP, nor is it intended to representthe current market value of the estimated oil and natural gas reserves owned bythe Company. PV-10 Value should not be considered in isolation or as asubstitute for the standardized measure of discounted future net cash flows asdefined under GAAP.

 

The reserve data set forth herein representsestimates only. Reserve engineering is a subjective process of estimatingunderground accumulations of oil and natural gas that cannot be measured in anexact manner, and the accuracy of any reserve estimate is a function of thequality of available data and of engineering and geological interpretation andjudgment. As a result, estimates made by different engineers often vary fromone another. In addition, results of drilling, testing and productionsubsequent to the date of an estimate may justify revision of suchestimates, and such revisions may be material. Accordingly, reserveestimates are generally different from the quantities of oil and natural gasthat 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. No estimates of proved reservescomparable to those included herein have been included in reports to anyfederal agency other than the SEC.

 

In accordance with SEC regulations, the RyderScott Report and the WDVG Report each used year-end oil and natural gas pricesin effect at December 31, 2005, adjusted for basis and qualitydifferentials. The prices used in calculating the estimated future net revenueattributable to proved reserves do not necessarily reflect market prices foroil and natural gas production subsequent to December 31, 2005. There canbe no assurance that all of the proved reserves will be produced and soldwithin the periods indicated, that the assumed prices will actually be realizedfor such production or that existing contracts will be honored or judiciallyenforced. In particular, natural gas prices at December 31, 2005 were ator near their record highs. While crude oil prices have remained approximatelythe same since year-end, natural gas prices have experienced significantvolatility and since that time prices for natural gas have fallen substantially.As of March 1, 2006, the average price of natural gas that the Companyreceives for its production had fallen to approximately $6.50 per Mcf. Decreasesin the assumed commodity prices result in decreases in estimated future netrevenue as well as in estimated reserves.

 

# **Oiland Natural Gas Reserve Replacement**

#  

Finding and developing sufficient amounts of naturalgas and crude oil reserves at economical costs are critical to our long-termsuccess. Our business, as with other extractive businesses, is a depleting onein which each gas equivalent unit produced must be replaced or our asset baseand capacity to generate revenues in the future will shrink. Given the inherentdecline of reserves resulting from the production of those reserves, it isimportant for an exploration and production company to demonstrate a long-termtrend of more than offsetting produced volumes with new reserves that willprovide for future production. We use the reserve replacement ratio, as definedbelow, as an indicator of our ability to replenish annual production volumesand grow our reserves, thereby providing some information on the sources offuture production. We believe that reserve replacement is relevant and usefulinformation that is commonly used by analysts, investors and other interestedparties in the oil and gas industry as a means of evaluating the operationalperformance and to a greater extent the prospects of entities engaged in theproduction and sale of depleting natural resources. These measures are oftenused as a metric to evaluate an entity’s historical track record of replacingthe reserves that it produced. The reserve replacement ratio is calculated bydividing the sum of reserve additions from all sources (revisions, purchases,extensions and discoveries) by the actual production for the correspondingperiod. Additions to our reserves are proven developed and proven undevelopedreserves. We expect to continue adding to our reserve base through theseactivities, but certain factors outside our control may impede our abilityto do so (see *ITEM 1A. “RISK FACTORS*”). Thevalues for these reserve additions and production are derived directly from theproved reserves table in Note 20 to our consolidated financial statements.Accordingly, we do not use unproved reserve quantities. It should be noted thatthe reserve replacement ratio is a statistical indicator that has limitations.As an annual measure, the ratio is limited because it typically varies widelybased on the extent and timing of new discoveries and property acquisitions.Its predictive and comparative value is also limited for the same reasons. Inaddition, since the ratio does not consider the cost or timing of futureproduction of new reserves, it cannot be used as a measure of value creation.The ratio does not distinguish between changes in reserve quantities that aredeveloped and those that will require additional time and funding to develop.In that regard, it might be noted that the percentage of reserves that weredeveloped was 74%, 75% and 78% for the years ended December 31, 2005, 2004and 2003, respectively. Set forth below is our reserve replacement ratio forthe years ended December 31, 2005, 2004 and 2003.

 

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| ** **                | ** ** | **For the year ended December 31,** | ** ** | ** ** | ** ** |
|---------------------------|------------|--------------------------------------------------------------|------------|------------|------------|
| ** **                | ** ** | **2005**                                                     | ** ** | **2004**   | ** ** | **2003** | ** ** | **Three Year Average** | ** ** |
| Reserve Replacement Ratio |       | 184                                                          | %          | 308        | %          | 285 | % | 247 | % |

 

# **Oiland Natural Gas Volumes, Prices and Operating Expense**

 

The following table sets forth certain informationregarding production volumes, average sales prices and average operatingexpenses associated with our sale of oil and natural gas for the periodsindicated.

 
| ** **                                                         | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                         | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| **Production:**                                                    |       |                                       |       |   |   |   |   |
| Oil and condensate  (MBbls)                                        |       | 324                                        |       | 215 |   | 123 |   |
| Natural gas  liquids (MBbls)                                       |       | 308                                        |       | 276 |   | 178 |   |
| Natural gas  (MMcf)                                                |       | 12,597                                     |       | 9,148 |   | 6,290 |   |
| Natural gas  equivalent (MMcfe)                                    |       | 16,384                                     |       | 12,093 |   | 8,093 |   |
| **Average Sales Price - before hedging and  derivatives:**         |       |                                       |       |   |   |   |   |
| Oil and  condensate ($per Bbl)                                     |       | $                                          | 53.57      |   | $ | 39.77 |   | $ | 31.48 |   |
| Natural gas  liquids ($per Bbl)                                    |       | 18.45                                      |       | 15.83 |   | 12.37 |   |
| Natural gas  ($per Mcf)                                            |       | 7.97                                       |       | 5.91 |   | 5.14 |   |
| Natural gas  equivalent ($per Mcfe)                                |       | 7.53                                       |       | 5.54 |   | 4.74 |   |
| **Average Sales Price - after hedging and  derivatives:**          |       |                                       |       |   |   |   |   |
| Oil and  condensate ($per Bbl)                                     |       | $                                          | 50.36      |   | $ | 33.03 |   | $ | 31.48 |   |
| Natural gas  liquids ($per Bbl)                                    |       | 18.45                                      |       | 15.83 |   | 12.37 |   |
| Natural gas  ($per Mcf)                                            |       | 7.88                                       |       | 5.80 |   | 4.43 |   |
| Natural gas  equivalent ($per Mcfe)                                |       | 7.40                                       |       | 5.33 |   | 4.19 |   |
| **Average oil and natural gas operating  expenses ($per Mcfe)(1)** |       | $                                          | 0.52       |   | $ | 0.41 |   | $ | 0.33 |   |
| **Average  production and ad valorem taxes ($per Mcfe)**           |       | $                                          | 0.52       |   | $ | 0.36 |   | $ | 0.30 |   |

 

----

(1)          Includes direct lifting costs (labor, repairs and maintenance, materialsand supplies), expensed workover costs, the administrative costs of fieldproduction personnel, and insurance costs.

 

**Exploration, Development andAcquisition Capital Expenditures**

 

The following table sets forth certain informationregarding the total costs incurred in connection with exploration, developmentand acquisition activities.

 
| ** **                 | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------|------------|--------------------------------------------|------------|
| ** **                 | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                 | ** ** | **(in thousands)**                    | ** ** |
| Acquisition costs:         |       |                                       |       |   |   |   |   |
| Unproved  properties       |       | $                                          | 33,948     |   | $ | 12,163 |   | $ | 6,052 |   |
| Proved  properties (1)     |       | 66,472                                     |       | 33,980 |   | 10,374 |   |
| Exploration  costs         |       | 20,426                                     |       | 8,297 |   | 6,017 |   |
| Development costs          |       | 58,685                                     |       | 34,548 |   | 12,271 |   |
| Subtotal                   |       | 179,531                                    |       | 88,988 |   | 34,714 |   |
| Asset retirement costs (2) |       | 436                                        |       | 278 |   | 898 |   |
| Total costs  incurred      |       | $                                          | 179,967    |   | $ | 89,266 |   | $ | 35,612 |   |

 

----

| (1) | Includes $17.8 million added to property acquired in the Cinco  acquisition associated with recording a deferred tax liability at the date of  acquisition for taxable temporary differences existing at the purchase date  in accordance with SFAS No. 109 (see Notes 6 and 14 to our consolidated  financial statements). |
|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (2) | Excluded from asset retirement costs in 2003 was $640,400 related to  the cumulative effect of the adoption of SFAS No. 143 on January 1,  2003. See Note 7 to our consolidated financial statements.                                                                                                             |

 

8

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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 wouldsignificantly alter the relationship between capitalized costs and provedreserves.

 

**Drilling Activity**

 

The following table sets forth our drilling activityfor the years ended December 31, 2005, 2004 and 2003. In the table, “Gross”refers to the total wells in which we have a working interest or back-inworking interest after payout and “Net” refers to gross wells multiplied by ourworking interest therein.

 
| ** **        | ** ** | **Year Ended December 31,** | ** ** |
|-------------------|------------|--------------------------------------------|------------|
| ** **        | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **        | ** ** | **Gross**                                  | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Exploratory:**  |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Productive        |       | 16                                         |       | 6.44 |   | 5 |   | 2.35 |   | 10 |   | 7.05 |   |
| Non-productive    |       | 1                                          |       | 0.75 |   | 5 |   | 2.50 |   | 8 |   | 4.25 |   |
| Total             |       | 17                                         |       | 7.19 |   | 10 |   | 4.85 |   | 18 |   | 11.30 |   |
| **Development:**  |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Productive        |       | 46                                         |       | 26.51 |   | 35 |   | 19.33 |   | 18 |   | 6.62 |   |
| Non-productive    |       | 2                                          |       | 1.75 |   | 4 |   | 2.73 |   | — |   | — |   |
| Total             |       | 48                                         |       | 28.26 |   | 39 |   | 22.06 |   | 18 |   | 6.62 |   |
| **Grand Total**   |       | 65                                         |       | 35.45 |   | 49 |   | 26.91 |   | 36 |   | 17.92 |   |
| ** **        |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| **Success Ratio** | ** ** | **95**                                     | **%**      | **93** | **%** | **82** | **%** | **81** | **%** | **78** | **%** | **76** | **%** |

 

# **ProductiveWells**

#  

The following table sets forth the number ofproductive oil and natural gas wells in which we owned an interest as of December 31,2005.

 
| ** **  | ** ** | **Company-Operated** | ** ** | **Non-Operated** | ** ** | **Total** | ** ** |
|-------------|------------|----------------------|------------|------------------|------------|-----------|------------|
| ** **  | ** ** | **Gross**            | ** ** | **Net**          | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|        |       |                 |       |             |       |      |       |   |   |   |   |   |   |
| Oil         |       | 23                   |       | 13.32            |       | 30        |       | 34.87 |   | 53 |   | 48.19 |   |
| Natural gas |       | 91                   |       | 73.62            |       | 234       |       | 139.43 |   | 325 |   | 213.05 |   |
| Total       |       | 114                  |       | 86.94            |       | 264       |       | 174.30 |   | 378 |   | 261.24 |   |

 

# **AcreageData**

 

The following table sets forth certain informationregarding our developed and undeveloped lease acreage as of December 31,2005. Developed acres refer to acreage within producing units and undevelopedacres refer to acreage that has not been placed in producing units.

 

9

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| ** **  | ** ** | **Developed Acres** | ** ** | **Undeveloped Acres** | ** ** | **Total** | ** ** |
|-------------|------------|---------------------|------------|-----------------------|------------|-----------|------------|
| ** **  | ** ** | **Gross**           | ** ** | **Net**               | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|        |       |                |       |                  |       |      |       |   |   |   |   |   |   |
| Arkansas    |       | —              |       | —                |       | 5,420     |       | 4,571 |   | 5,420 |   | 4,571 |   |
| Montana     |       | —              |       | —                |       | 15,166    |       | 11,652 |   | 15,166 |   | 11,652 |   |
| Michigan    |       | 160                 |       | 160                   |       | 498       |       | 498 |   | 658 |   | 658 |   |
| Alabama     |       | 536                 |       | 3                     |       | 40        |       | 1 |   | 576 |   | 4 |   |
| Louisiana   |       | 2,261               |       | 464                   |       | 1,605     |       | 342 |   | 3,866 |   | 806 |   |
| New Mexico  |       | 6,889               |       | 2,014                 |       | 89,932    |       | 17,084 |   | 96,821 |   | 19,098 |   |
| Mississippi |       | 9,942               |       | 3,208                 |       | 48,123    |       | 36,879 |   | 58,065 |   | 40,087 |   |
| Texas       |       | 66,715              |       | 27,874                |       | 16,824    |       | 6,595 |   | 83,539 |   | 34,469 |   |
| Total       |       | 86,503              |       | 33,723                |       | 177,608   |       | 77,622 |   | 264,111 |   | 111,345 |   |

 

Leases covering approximately 4,215 gross (2,661net), 12,443 gross (9,604 net) and 25,291 gross (19,647 net) undeveloped acresare scheduled to expire in 2006, 2007 and 2008, respectively. In general, ourleases will continue past their primary terms if oil and natural gas productionin commercial quantities is being produced from a well on such lease.

 

### **The table does not include 67,154gross (44,977 net) undeveloped acres in Texas for which we have the option toacquire leases based upon a commitment of continuous drilling subject to thefollowing:**

 
| **Options Expire*** | ** ** | **Gross Acres** | ** ** | **Net Acres** | ** ** |
|--------------------------|------------|----------------------|------------|--------------------|------------|
| 2006                     |       | 13,564               |       | 6,782              |       |
| 2007                     |       | 7,990                |       | 3,995              |       |
| 2008                     |       | 45,600               |       | 34,200             |       |
|                     |       |                 |       |               |       |
| Total                    |       | 67,154               |       | 44,977             |       |

 

----

###### *** This isan estimate of the expiration of our option to acquire leased acreage based onour current well and seismic 3-D acquisition schedule.**

######  

# **CoreAreas of Operation**

 

As of December 31, 2005, 84.1% of our provedreserves were in south Texas, 6.0% in Mississippi, 5.8% in New Mexico, and 4.1%in south Louisiana, Michigan, and Alabama. During 2005, we added reserves andproduction through our drilling program, focused in south Texas andsoutheastern New Mexico, and our acquisition program, primarily the ChapmanRanch Field acquisitions.

 

The table below sets forth the gross and net numberof our gas, oil and service wells in each of our core areas of operation as of December 31,2005.

 
| ** **  | ** ** | **Gas Wells** | ** ** | **Oil Wells** | ** ** | **Service Wells (1)** | ** ** |
|-------------|------------|--------------------|------------|--------------------|------------|---------------------------------|------------|
| ** **  | ** ** | **Gross**          | ** ** | **Net**            | ** ** | **Gross**                       | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Texas       |       | 261                |       | 81.21              |       | 41                              |       | 5.47 |   | 4 |   | 1.83 |   |
| Louisiana   |       | 6                  |       | 1.16               |       | 1                               |       | 0.24 |   | 2 |   | 0.18 |   |
| Mississippi |       | 12                 |       | 5.65               |       | 18                              |       | 3.90 |   | 3 |   | 0.35 |   |
| Alabama     |       | —             |       | —             |       | 6                               |       | 0.42 |   | 3 |   | 1.26 |   |
| Michigan    |       | 1                  |       | 1.00               |       | —                          |       | — |   | — |   | — |   |
| New Mexico  |       | 13                 |       | 4.47               |       | 19                              |       | 8.71 |   | — |   | — |   |
| Total       |       | 293                |       | 93.49              |       | 85                              |       | 18.74 |   | 12 |   | 3.62 |   |

 

----

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

 

10

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# ***Texas***

 

We currently own an interest in 83,539 gross (34,469net) acres in south and south-central Texas. Our areas of focus in this regionare predominantly in the Wilcox (Lobo), Queen City, Yegua, Vicksburg and Frioproducing trends. As of December 31, 2005, we operated approximately 87 producingwells, which along with our 215 non-operated wells accounted for about 83% ofour total net production. We drilled 47 wells during 2005 in Texas, 44 of whichwere an apparent success. The majority of our 2005 drilling activity took placein the Queen City, Gato Creek (Lobo), and Encinitas (Vicksburg) project areas.We drilled 23 apparently successful wells in the Queen City project area, eightat Gato Creek and seven at Encinitas. In 2006, we currently expect to drill 35 to40 wells (22.4 to 25.6 net, respectively) in our core areas in Texas. Themajority of these wells are planned in the Queen City project area, theEncinitas Field and the Chapman Ranch Field.

 

TheChapman Ranch Field acquisitions increased our Texas property base in 2005. Theseacquisitions added to our existing position, notably in the Deep Frio trend in NuecesCounty, Texas (see Note 6 to our consolidated financial statements).

 

# ***Louisiana***

 

We currently own an interest in 3,866 gross (806 net)acres in south Louisiana primarily located in Acadia, Calcasieu, Lafayette, St.Landry and Vermilion Parishes. As of December 31, 2005, we had an interestin 7 wells, none of which we operate. We have no current plans to drilladditional wells in this area in 2006.

 

# ***Mississippi***

 

We currently own an interest in 20,948 gross (9,493 net)acres in Mississippi in the Mississippi Salt Basin area and an additional 37,117gross (30,594 net) undeveloped acres in the Floyd Shale play. We acquiredreserves 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 the Mississippi Salt Basin around the Millerproperties include the Hosston, Sligo, Rodessa and James Lime sections. As of December 31,2005, we operated nine producing wells, accounting for approximately 90% of ourtotal net production in Mississippi. In 2005 we established a position in theFloyd Shale play in east central Mississippi. In 2006, we plan to increase ourleasehold position, acquire additional 3-D seismic and could drill one to twowells (0.8 to 1.3 net) in the Mississippi Salt Basin.

 

# ***Michigan***

 

We currently own an interest in 658 gross (658 net)acres in Michigan. We acquired acreage and one producing well in south centralMichigan as part of the 2003 merger with Miller. We operate this well whichproduces from the Trenton/Black River formation at approximately 3,000 feet. Wehave no plans for additional activity in Michigan in 2006 at this time.

 

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

 

We established a new core area in southeastern NewMexico through an alliance with two private companies in 2003. We currently ownan interest in 95,541 gross (18,777 net) acres in this area that we earnedthrough a drilling obligation that we fulfilled during 2004 and 2005. 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 2005, we participated in the drilling of 11 (4.2 net) shallow and seven (2.2net) deep wells. All of the wells were apparent successes. We also acquired anadditional 1,280 gross (321 net) acres from federal and state lease sales.During 2006, we anticipate drilling 14 to 16 wells (5.4 to 5.8 net) wells inNew Mexico, and also anticipate adding to our acreage position in this areathrough lease sale acquisitions.

 

# ***Arkansas***

 

We currently own an interest in 5,420 gross (4,571 net)undeveloped acres in the Fayetteville Shale play in south central Arkansas. In2006, we plan to acquire additional acreage in this area.

 

11

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

 

We believe we have satisfactory title to all of ourproducing properties in accordance with standards generally accepted in the oiland natural gas industry. Our properties are subject to customary royaltyinterests, liens incident to operating agreements, liens for current taxes andother burdens, which we believe do not materially interfere with the use of oraffect the value of such properties. As is customary in the industry in thecase of undeveloped properties, little investigation of record title is made atthe time of acquisition (other than a preliminary review of local records). Detailedinvestigations, including a title opinion rendered by a licensed attorney, aremade before commencement of drilling operations.

 

We have granted mortgage liens on substantially allof our oil and natural gas properties in favor of Union Bank of California, asagent, to secure our credit facility. These mortgages and the credit facilitycontain substantial restrictions and operating covenants that are customarilyfound 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**

 

Our production is marketed to third partiesconsistent with industry practices. We market our own production where feasible,but on occasion engage a third-party marketing agent. Typically, oil is sold atthe well-head at field-posted prices and natural gas is sold under contract ata negotiated monthly price based upon factors normally considered in theindustry, such as conditioning or treating to make gas marketable, distancefrom the well to the transportation pipeline, well pressure, estimatedreserves, quality of natural gas and prevailing supply/demand conditions.

 

Our marketing objective is to receive the highestpossible wellhead price for our product. We are aided by the presence ofmultiple outlets near our production on the Gulf Coast. We take an active rolein determining the available pipeline alternatives for each property based uponhistorical pricing, capacity, pressure, market relationships, seasonalvariances and long-term viability.

 

There are a variety of factors which affect themarket for oil and natural gas, including the extent of domestic production andimports of oil and natural gas, the proximity and capacity of natural gaspipelines and other transportation facilities, demand for oil and natural gas,the marketing of competitive fuels and the effects of state and federalregulations on oil and natural gas production and sales. We have not experiencedany significant difficulties in marketing our oil and natural gas. The oil andnatural gas industry also competes with other industries in supplying theenergy and fuel requirements of industrial, commercial and individualcustomers.

 

Where feasible, we use a combination ofmarket-sensitive pricing and forward-fixed pricing. Forward pricing is utilizedto take advantage of anomalies in the futures market and to hedge a portion ofour production at prices exceeding forecast. All such hedging transactions providefor financial rather than physical settlement. See *ITEM 7. “MANAGEMENT’SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS –*CRITICAL ACCOUNTING POLICIESAND ESTIMATES – DERIVATIVES AND HEDGING ACTIVITIES*.”*

 

Due to the instability of oil and natural gasprices, we may enter into, from time to time, price risk managementtransactions (e.g., swaps, collars and floors) for a portion of our oil andnatural gas production to achieve a more predictable cash flow, as well as toreduce exposure to price fluctuations. While the use of these arrangements may limitour ability to benefit from increases in the price of oil and natural gas, italso reduces our potential exposure to adverse price movements. Our price riskmanagement arrangements, to the extent we enter into any, apply to only aportion of our production, provide only partial price protection againstdeclines in oil and natural gas prices and limit our potential gains fromfuture increases in prices. On an ongoing basis, our management reviews all ofour price risk management transaction policies, including volumes, accountingtreatment, types of instruments and counter parties. These policies areimplemented by management through the execution of trades by the ChiefFinancial Officer after consultation with and concurrence by the President andChairman of the Board. Our Board of Directors reviews our price risk managementpolicies and trades. We account for these transactions as hedging andderivative activities and, accordingly, certain gains and losses are includedin revenue during the period the transactions occur (see Note 9 to ourconsolidated financial statements).

 

12

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Although we take some measures to attempt to control price risk, weremain subject to price fluctuations for natural gas sold in the spot marketdue primarily to seasonality of demand and other factors beyond our control. Domesticoil prices generally follow worldwide oil prices, which are subject to pricefluctuations resulting from changes in world supply and demand. We continue toevaluate the potential for reducing these risks by entering into hedgetransactions. Included within total revenue for the years ended December 31,2005, 2004, and 2003 was approximately $2.3 million, $2.5 million and $4.5million, respectively, representing net losses from hedging and derivativeactivity as shown in the table below.

 
| ** **                                                                 | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                 | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| Natural gas  hedging contract settlements                                  |       | $                                          | (1,229,900 | ) | $ | (328,500 | ) | $ | (4,455,590 | ) |
| Crude oil  derivative contract settlements                                 |       | (1,757,766                                 | )          | (880,765 | ) | — |   |
| Hedge  premium reclassification                                            |       | —                                     |       | (686,250 | ) | — |   |
| Mark-to-market  reversal of prior period unrealized change in fair value   |       | 564,548                                    |       | — |   | — |   |
| Mark-to-market  unrealized change in fair value of oil derivative contract |       | 155,865                                    |       | (564,548 | ) | — |   |
|                                                                       |       |                                       |       |   |   |   |   |
| Loss on  hedging and derivatives                                           |       | $                                          | (2,267,253 | ) | $ | (2,460,063 | ) | $ | (4,455,590 | ) |

 

The table below summarizes our outstanding hedge and derivative contractsreflected on the balance sheet at December 31, 2005 and 2004.

 
| ** **                | ** ** | ** **                | ** ** | ** **    | ** ** | ** ** | ** ** | ** **        | ** **   | ** **       | ** **  | **Fair Value of Outstanding Hedging and  Derivative Contracts as of** | ** ** |
|---------------------------|------------|---------------------------|------------|---------------|------------|------------|------------|-------------------|--------------|------------------|-------------|---------------------------------------------------------------------------------------------------------------|------------|
| ** **                | ** ** | ** **                | ** ** | ** **    | ** ** | ** ** | ** ** | **Price**         | ** **   | **Volumes**      | ** **  | **December 31,**                                                                                         | ** ** |
| **Transaction Date** | ** ** | **Transaction Type** | ** ** | **Beginning** | ** ** | **Ending** | ** ** | **Per Unit** | ** **   | **Per Day** | ** **  | **2005**                                                                                                      | ** ** | **2004(4)** | ** ** |
| ***Natural  Gas (1):***   |       |                      |       |          |       |       |       |              |         |             |        |                                                                                                          |       |   |   |
| 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 |   |
| 08/05                     |       | Natural Gas  Collar       |       | 01/01/2006    |       | 12/31/2006 |       | $                 | 7.00-$10.50  |             | 10,000MMbtu |                                                                                                          | (2,497,823 | ) | — |   |
| 08/05                     |       | Natural Gas  Collar       |       | 01/01/2006    |       | 12/31/2006 |       | $                 | 7.00-$16.10  |             | 10,000MMbtu |                                                                                                          | (137,077   | ) | — |   |
| ***Crude  Oil (2):***     |       |                      |       |          |       |       |       |              |         |             |        |                                                                                                          |       |   |   |
| 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  (3)     |       | 01/01/2005    |       | 12/31/2005 |       | $                 | 35.00-$40.00 |             | 200/290Bbl  |                                                                                                          | —     |   | (468,308 | ) |
| 08/05                     |       | Crude Oil Collar          |       | 01/01/2006    |       | 12/31/2006 |       | $                 | 55.00-$80.00 |             | 400Bbl      |                                                                                                          | 155,865    |   | —- |   |
|                      |       |                      |       |          |       |       |       |              |         |             |        |                                                                                                          |       |   |   |
|                      |       |                      |       |          |       |       |       |              |         |             |        | $                                                                                                             | (2,479,035 | ) | $ | 1,356,482 |   |

 

----

(1)                Ourcurrent 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)                Hedge accountingis not applied to our 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 total revenue.

(3)                In August 2004,we replaced the contract that was entered into May 2004 with a newcontract that changes the volume and pricing terms. The put option is on 200Bbls/d and the call option is on 290 Bbls/d. This transaction was completed atno additional cost to us.

(4)                The fair value of ouroutstanding transactions is presented on the balance sheet by counterparty. Ourcounterparties net our positions with them, but we cannot present the net ofthe two counterparty positions because we do not have legal right of offset.Therefore one counterparty is presented in the Derivative Asset and one ispresented in the Derivative Liability. The crude oil collar with a balance of($468,308) is presented as a liability and the remaining contracts arepresented as an asset. All contracts are considered current.

 

13

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# **Salesto Major Customers**

 

We sold natural gas and crude oil productionrepresenting 10% or more of our total revenues for the years ended December 31,2005, 2004, and 2003 as listed below.

 
| ** **                   | ** ** | **For the year ended December 31,** | ** ** |
|------------------------------|------------|--------------------------------------------------------------|------------|
| **Purchaser**                | ** ** | **2005**                                                     | ** ** | **2004** | ** ** | **2003** | ** ** |
| Kinder Morgan                |       | 29%                                                          |       | * |   | * |   |
| ChevronTexaco                |       | 18%                                                          |       | 22% |   | 6% |   |
| Copano Field Services        |       | 17%                                                          |       | 19% |   | 16% |   |
| Upstream Energy Services (1) |       | 5%                                                           |       | 22% |   | 38% |   |
| BTA                          |       | *                                                            |       | 2% |   | 18% |   |

 

----

* Zero or less than 1%

(1) Upstream Energy Services is an agent thatsells our production to other purchasers on our behalf.

 

NOTE: Amounts disclosed are approximations and thosethat are less than 10% are presented for information and comparison purposesonly. Also these percentages do not consider the effects of financial hedges.

 

In the exploration, development and productionbusiness, production is normally sold to relatively few customers.Substantially all of the Company’s customers are concentrated in the oil andgas industry, and revenue can be materially affected by current economicconditions and the price of certain commodities such as natural gas and crudeoil, the cost of which is passed through to the customer. However, based on thecurrent demand for natural gas and crude oil and the fact that alternatepurchasers are readily available, we believe that the loss of any of our majorpurchasers would not have a long-term material adverse effect on ouroperations.

 

### **Competition**

 

We compete with other oil and natural gas companiesin all areas of our operations, including the acquisition of exploratoryprospects and proven properties. Our ability to explore for oil and natural gasreserves and to acquire additional properties in the future will be dependentupon our ability to conduct our operations, to evaluate and select suitableproperties and to consummate transactions in this highly competitive environment.We believe that our technological expertise, our exploration, land, drillingand production capabilities and the experience of our management generallyenable us to compete effectively. (See*ITEM 1A. “RISK FACTORS* – We facestrong competition from larger 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. Thesefactors include regulation of oil and natural gas production, federal and stateregulations governing environmental quality and pollution control, state limitson allowable rates of production by well or proration unit, the amount of oiland natural gas available for sale, the availability of adequate pipeline andother transportation and processing facilities and the marketing of competitivefuels. For example, a productive natural gas well may be “shut-in” becauseof an oversupply of natural gas or lack of an available natural gas pipeline inthe areas in which we may conduct operations. State and federalregulations generally are intended to prevent waste of oil and natural gas,protect rights to produce oil and natural gas between owners in a commonreservoir, control the amount of oil and natural gas produced by assigning allowablerates of production and control contamination of the environment. Pipelines aresubject to the jurisdiction of various federal, state and local agencies. Weare also subject to changing and extensive tax laws, the effects of whichcannot be predicted. The following discussion summarizes the regulation of theUnited States oil and natural gas industry. We believe that we are insubstantial compliance with the various statutes, rules, regulations andgovernmental orders to which our operations may be subject, although therecan be no assurance that this is or will remain the case. Moreover, suchstatutes, rules, regulations and government orders may be changed orreinterpreted 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. The following discussion is not intended to

 

14

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constitutea complete discussion of the various statutes, rules, regulations andgovernmental orders to which our operations may be subject.

 

*Regulation of Oil and Natural Gas Exploration and Production.*Our operations are subject to various typesof regulation at the federal, state and local levels. Such regulation includesrequiring permits for the drilling of wells, maintaining bonding requirementsin order to drill or operate wells and regulating the location of wells, themethod of drilling and casing wells, the surface use and restoration ofproperties upon which wells are drilled, the plugging and abandoning of wellsand the disposal of fluids used in connection with operations. Our operationsare also subject to various conservation laws and regulations. These includethe regulation of the size of drilling and spacing units or proration units andthe density of wells that may be drilled in and the unitization or poolingof oil and natural gas properties. In this regard, some states allow the forcedpooling or integration of tracts to facilitate exploration while other statesrely primarily or exclusively on voluntary pooling of lands and leases. Inareas where pooling is voluntary, it may be more difficult to form units,and therefore more difficult to develop a project, if the operator owns lessthan 100% of the leasehold. In addition, state conservation laws establishmaximum rates of production from oil and natural gas wells, generally prohibitthe venting or flaring of natural gas and impose certain requirements regardingthe ratability of production. The effect of these regulations may limitthe amount of oil and natural gas we can produce from our wells and may limitthe number of wells or the locations at which we can drill. The regulatoryburden on the oil and natural gas industry increases our costs of doingbusiness and, consequently, affects our profitability. Inasmuch such laws andregulations are frequently expanded, amended and interpreted, we are unable topredict the future cost or impact of complying with such regulations.

 

*Regulation of 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 NaturalGas Act (“NGA”) of 1938, the Federal Energy Regulatory Commission (the “FERC”)regulates the interstate transportation and the sale in interstate commerce forresale of natural gas. Effective January 1, 1993, the Natural GasWellhead Decontrol Act (the “Decontrol Act”) deregulated natural gas prices forall “first sales” of natural gas, including all sales by us of our ownproduction. As a result, all of our domestically produced natural gas may nowbe sold at market prices, subject to the terms of any private contracts that may bein effect. However, the Decontrol Act did not affect the FERC’s jurisdictionover natural gas transportation. Under the provisions of the Energy Policy Actof 2005, the NGA has been amended to prohibit any forms of market manipulationin connection with the purchase or sale of natural gas, and the FERC has issuednew regulations to implement this prohibition. In addition, under the 2005 Actthe FERC has been directed to establish new regulations that are intended toincrease natural gas pricing transparency through, among other things, expandeddissemination of information about the availability and prices of gas sold. The2005 Act also has significantly increased the penalties for violations of theNGA.

 

Our natural gas sales are affected by intrastate andinterstate gas transportation regulation. Following the Congressional passageof the NGPA, the FERC adopted a series of regulatory changes that havesignificantly altered the transportation and marketing of natural gas. Beginningwith the adoption of Order No. 436, issued in October 1985, the FERChas implemented a series of major restructuring orders that have requiredpipelines, among other things, to perform “open access” transportation ofgas for others, “unbundle” their sales and transportation functions, and allowshippers to release their unneeded capacity temporarily and permanently toother shippers. As a result of these changes, sellers and buyers of gas havegained direct access to the particular pipeline services they need and arebetter able to conduct business with a larger number of counterparties. Webelieve these changes generally have improved our access to markets while, atthe same time, substantially increasing competition in the natural gasmarketplace. It remains to be seen, however, what effect the FERC’s otheractivities will have on access to markets, the fostering of competition and thecost of doing business. We cannot predict what new or different regulations theFERC and other regulatory agencies may adopt, or what effect subsequentregulations may have on our activities. We do not believe that we will beaffected by any such new or different regulations materially differently thanany other seller of natural gas with which we compete.

 

In the past, Congress has been very active in thearea of gas regulation. However, as discussed above, the more recent trend hasbeen in favor of deregulation, or “lighter handed” regulation, and thepromotion of competition in the gas industry. There regularly are otherlegislative proposals pending in the Federal and state legislatures that, ifenacted, would significantly affect the petroleum industry. At the presenttime, it is impossible to predict what proposals, if any, might actually beenacted by Congress or the various state legislatures and what 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 

 

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salesof gas, cannot be predicted. Again, we do not believe that we will be affectedby any such new legislative proposals materially differently than any otherseller of natural gas with which we compete.

 

We own certain natural gas pipelines that we believemeet the standards the FERC has used to establish a pipeline’s status as agatherer not subject to FERC jurisdiction under the NGA. These gatheringfacilities are regulated for safety compliance by the U.S. Department ofTransportation (“DOT”) and/or by state regulatory agencies. In 2004, the DOTimplemented regulations requiring that pipeline operators implement a pipelineintegrity management program that must at a minimum include an inspection ofcertain pipeline facilities within ten years, and at least every seven yearsthereafter. In addition, beginning in early 2006, the DOT’s Pipeline andHazardous Materials Safety Administration commenced a rulemaking proceeding todevelop rules that would better distinguish onshore gathering lines fromproduction facilities and transmission lines, and to develop safetyrequirements better tailored to gathering line risks. We are not able topredict with certainty the final outcome of this rulemaking proposal. Inaddition to safety regulation, state regulation of gathering facilitiesgenerally includes various environmental, and in some circumstances,nondiscriminatory take requirements, but does not generally entail rate regulation.Natural gas gathering may receive greater regulatory rate and service scrutinyat the state level in the post-restructuring environment.

 

*Oil Price Controls and Transportation Rates.*Sales of crude oil, condensate and gasliquids by us are not currently regulated and are made at market prices. Theprice we receive from the sale of these products may be affected by thecost of transporting the products to market. Much of the transportation isthrough interstate common carrier pipelines. Effective as of January 1,1995, the FERC implemented regulations generally grandfathering all previouslyapproved interstate transportation rates and establishing an indexing systemfor those rates by which adjustments are made annually based on the rate ofinflation, subject to certain conditions and limitations. The FERC’s regulationof oil transportation rates may tend to increase the cost of transportingoil and natural gas liquids by interstate pipelines, although the annualadjustments may result in decreased rates in a given year. Every fiveyears, the FERC must examine the relationship between the annual change in theapplicable index and the actual cost changes experienced in the oil pipelineindustry. The second of these required reviews was commenced in July 2005,where the FERC has proposed to continue use of the indexing methodology for afurther five year period. We are not able at this time to predict the effectsof these regulations, if any, on the transportation costs associated with oilproduction from our oil producing operations.

 

*Environmental Regulations.*Our operations are subject to numerous federal, state and local lawsand regulations governing the discharge of materials into the environment orotherwise relating to environmental protection. These laws and regulations may requirethe acquisition of a permit before drilling commences, restrict the types,quantities and concentration of various substances that can be released intothe environment in connection with drilling and production activities, limit orprohibit drilling activities on certain lands within wilderness, wetlands andother protected areas, require remedial measures to mitigate pollution fromformer operations, such as pit closure and plugging abandoned wells, and imposesubstantial liabilities for pollution resulting from production and drillingoperations. Public interest in the protection of the environment has increaseddramatically 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. To the extent laws are enacted or othergovernmental action is taken that restricts drilling or imposes more stringentand costly waste handling, disposal and cleanup requirements, our business andprospects could be adversely affected.

 

We generate wastes that may be subject to thefederal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes.The U.S. Environmental Protection Agency (“EPA”) and various state agencieshave limited the approved methods of disposal for certain hazardous andnonhazardous wastes. Furthermore, certain wastes generated by our oil andnatural gas operations that are currently exempt from treatment as “hazardouswastes” may in the future be designated as “hazardous wastes,” andtherefore be subject to more rigorous and costly operating and disposalrequirements.

 

We currently own or lease numerous properties thatfor many years have been used for the exploration and production of oil andnatural gas. Although we believe that we have used good operating and wastedisposal practices, prior owners and operators of these properties may nothave used similar practices, and hydrocarbons or 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. Inaddition, many of these properties have been operated by third parties whosetreatment and disposal or release of hydrocarbons or other wastes was not underour control. These properties and the wastes disposed thereon may besubject to the Comprehensive Environmental Response, 

 

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Compensationand Liability Act (“CERCLA”), RCRA and analogous state laws as well as statelaws governing the management of oil and natural gas wastes. Under such laws,we could be required to remove or remediate previously disposed wastes(including wastes disposed of or released by prior owners or operators) orproperty contamination (including groundwater contamination) or to perform remedialplugging operations to prevent future contamination.

 

Our operations may be subject to the Clean AirAct (“CAA”) and comparable state and local requirements. Amendments to the CAAwere adopted in 1990 and contain provisions that have resulted in the gradualimposition of certain pollution control requirements with respect to airemissions from our operations. The EPA and states developed and continue todevelop regulations to implement these requirements. 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 notbelieve our operations will be materially adversely affected by any suchrequirements.

 

Federal regulations require certain owners oroperators of facilities that store or otherwise handle oil, such as Edge, toprepare and implement spill prevention, control, countermeasure (“SPCC”) andresponse plans relating to the possible discharge of oil into surface waters. SPCCplans at our producing properties were developed and implemented in 1999. TheOil Pollution Act of 1990 (“OPA”) contains numerous requirements relating tothe prevention of and response to oil spills into waters of the United States. TheOPA subjects owners of facilities to strict joint and several liability for allcontainment and cleanup costs and certain other damages arising from a spill,including, but not limited to, the costs of responding to a release of oil tosurface waters. Noncompliance with OPA may result in varying civil andcriminal penalties and liabilities. Our operations are also subject to thefederal Clean Water Act (“CWA”) and analogous 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. LikeOPA, the CWA and analogous state laws relating to the control of waterpollution provide varying civil and criminal penalties and liabilities forreleases of petroleum or its derivatives into surface waters or into theground.

 

CERCLA, also known as the “Superfund” law, andsimilar state laws impose liability, without regard to fault or the legality ofthe original conduct, on certain classes of persons that are considered to havecontributed to the release of a “hazardous substance” 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 responsiblefor releases of hazardous substances under CERCLA may be subject to jointand several liability for the costs of cleaning up the hazardous substancesthat have been released into the environment, for damages to natural resourcesand for the costs of certain health studies, and it is not uncommon forneighboring landowners and other third parties to file claims for personalinjury and property damage allegedly caused by the hazardous substancesreleased into the environment.

 

We also are subject to a variety of federal, stateand local permitting and registration requirements relating to protection ofthe environment. Management believes that we are in substantial compliance withcurrent applicable environmental laws and regulations and that continuedcompliance with existing requirements would not have a material adverse effecton us.

 

# **OPERATING HAZARDS AND INSURANCE**

 

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

 

In accordance with customary industry practice, wemaintain insurance against some, but not all, of the risks described above. Ourinsurance does not cover business interruption or protect against loss ofrevenue. There can be no assurance that any insurance obtained by us will beadequate to cover any losses or liabilities. We cannot predict the continuedavailability of insurance or the availability of insurance at premium levelsthat justify its purchase. The occurrence of a significant event not fullyinsured or indemnified against could materially and adversely affect ourfinancial condition and operations.

 

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***ITEM 1A. RISK FACTORS***

 

**Oil and gas drilling is a speculative activity and involves numerousrisks and substantial and uncertain costs****whichcould adversely affect us.**

 

Our growth will be materially dependent upon thesuccess of our future drilling program. Drilling for oil and gas involvesnumerous risks, including the risk that no commercially productive oil or naturalgas reservoirs will be encountered. The cost of drilling, completing andoperating wells is substantial and uncertain, and drilling operations may becurtailed, delayed or cancelled as a result of a variety of factors beyond ourcontrol, including unexpected drilling conditions, pressure or irregularitiesin formations, equipment failures or accidents, adverse weather conditions,compliance with governmental requirements and shortages or delays in theavailability of drilling rigs or crews and the delivery of equipment. Ourfuture drilling activities may not be successful and, if unsuccessful,such failure will have an adverse effect on our future results of operationsand financial condition. Our overall drilling success rate or our drillingsuccess rate for activity within a particular geographic area may decline.We may ultimately not be able to lease or drill identified or budgetedprospects within our expected time frame, or at all. We may not be able tolease or drill a particular prospect because, in some cases, we identify aprospect or drilling location before seeking an option or lease rights in theprospect or location. Similarly, our drilling schedule may vary fromour capital budget. The final determination with respect to the drilling of anyscheduled or budgeted wells will be dependent on a number of factors,including:

 

•                  theresults of exploration efforts and the acquisition, review and analysis of theseismic data;

•                  theavailability of sufficient capital resources to us and the other participantsfor the drilling of the prospects;

•                  theapproval of the prospects by other participants after additional data has beencompiled;

•                  economicand industry conditions at the time of drilling, including prevailing andanticipated prices for oil and natural gas and the availability of drillingrigs and crews;

•                  ourfinancial resources and results; and

•                  theavailability of leases and permits on reasonable terms for the prospects.

 

Theseprojects may not be successfully developed and the wells, if drilled, may notencounter reservoirs of commercially productive oil or natural gas. See *ITEM 7. “MANAGEMENT’S DISCUSSIONAND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS* – GENERAL OVERVIEW - INDUSTRY AND ECONOMICFACTORS*”* and *ITEMS 1 AND2. “BUSINESS AND PROPERTIES –*COREAREAS OF OPERATION.”

 

**Oil and natural gas prices are highly volatile in general and lowprices negatively affect our financial results.**

 

Our revenue, profitability, cash flow, future growthand ability to borrow funds or obtain additional capital, as well as thecarrying value of our properties, are substantially dependent upon prevailingprices of oil and natural gas. Our reserves are predominantly natural gas,therefore changes in natural gas prices may have a particularly largeimpact on our financial results. Lower oil and natural gas prices also may reducethe amount of oil and natural gas that we can produce economically.Historically, the markets for oil and natural gas have been volatile, and suchmarkets are likely to continue to be volatile in the future. Prices for oil andnatural gas are subject to wide fluctuation in response to relatively minorchanges in the supply of and demand for oil and natural gas, market uncertaintyand a variety of additional factors that are beyond our control. These factorsinclude the level of consumer product demand, weather conditions, domestic andforeign governmental regulations, the price and availability of alternativefuels, political conditions, the foreign supply of oil and natural gas, theprice of foreign imports and overall economic conditions. Declines in oil andnatural gas prices may materially adversely affect our financialcondition, liquidity, and ability to finance planned capital expenditures andresults of operations. See *ITEM 7. “MANAGEMENT’SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS*–RISK MANAGEMENT ACTIVITIES - DERIVATIVESAND HEDGING” and*ITEMS 1 AND 2. “BUSINESSAND PROPERTIES*— OIL AND NATURAL GAS RESERVES” and “–* *MARKETING*.”*

 

We have in the past and may in the future berequired to write down the carrying value of our oil and natural gas propertieswhen oil and natural gas prices are depressed or unusually volatile. Whether wewill 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 orrevisions and capital expenditures during such quarter. If a write down isrequired, it would result in a charge to earnings, but would not impact cashflow from operating activities.

 

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**We have hedged and may continue to hedge aportion of our production, which may result in our making cash payments orprevent us from receiving the full benefit of increases in prices for oil andgas.**

 

In order to reduce our exposure to short-termfluctuations in the price of oil and natural gas, we periodically enter intohedging arrangements. Our hedging arrangements apply to only a portion of ourproduction and provide only partial price protection against declines in oiland natural gas prices. Such hedging arrangements may expose us to risk offinancial loss in certain circumstances, including instances where productionis less than expected, our customers fail to purchase contracted quantities ofoil or natural gas or a sudden, unexpected event materially impacts oil ornatural gas prices. In addition, our hedging arrangements may limit thebenefit to us of increases in the price of oil and natural gas. See *ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONAND RESULTS OF OPERATIONS –*RISK MANAGEMENT ACTIVITIES - DERIVATIVES AND HEDGING” and*ITEMS 1 AND 2. “BUSINESS AND PROPERTIES –*MARKETING.”

 

**We depend on successful exploration, development and acquisitions tomaintain reserves and revenue in the future.**

 

In general, the volume of production from oil andnatural gas properties declines as reserves are depleted, with the rate ofdecline depending on reservoir characteristics. Except to the extent we acquireproperties containing proved reserves or conduct successful exploration anddevelopment activities, or both, our proved reserves will decline. Our futureoil and natural gas production is, therefore, highly dependent upon our levelof success in finding or acquiring additional reserves. In addition, we aredependent on finding partners for our exploratory activity. To the extent thatothers in the industry do not have the financial resources or choose not toparticipate in our exploration activities, we could be adversely affected.

 

**We are subject to substantial operating risks that may adverselyaffect the results of our operations.**

 

The oil and natural gas business involves certainoperating hazards such as well blowouts, mechanical failures, explosions, uncontrollableflows of oil, natural gas or well fluids, fires, formations with abnormalpressures, pollution, releases of toxic gas and other environmental hazards andrisks. We could suffer substantial losses as a result of any of these events. Weare not fully insured against all risks incident to our business.

 

We are not the operator of some of our wells. As aresult, our operating risks for those wells and our ability to influence theoperations for these wells are less subject to our control. Operators of thesewells may act in ways that are not in our best interests. See*****ITEMS 1 AND 2. “BUSINESSAND PROPERTIES –*OPERATINGHAZARDS AND INSURANCE.”

 

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

 

We do not operate all ofthe properties in which we have an interest. As a result, we have limitedability to exercise influence over, and control the risks associated with,operations of these properties. The failure of an operator of our wells toadequately perform operations, an operator’s breach of the applicableagreements or an operator’s failure to act in ways that are in our bestinterest could reduce our production and revenues. The success and timing ofour drilling and development activities on properties operated by otherstherefore depend upon a number of factors outside of our control, including theoperator’s

 

•                  timing and amountof capital expenditures;

•                  expertise andfinancial resources;

•                  inclusion of otherparticipants in drilling wells; and

•                  use of technology.

 

**The loss of key personnel could adversely affect us.**

 

We depend to a large extent on the services ofcertain key management personnel, including our executive officers and otherkey employees, the loss of any of which could have a material adverse effect onour operations. We do not maintain key-man life insurance with respect to anyof our employees. We believe that our success is also dependent upon ourability to continue to employ and retain skilled technical personnel. See *ITEM 4.*

 

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*“SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS –*EXECUTIVE OFFICERS OF THE REGISTRANT” and “-SIGNIFICANTEMPLOYEES*.”*

 

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

 

We have experienced and expect to continue toexperience substantial working capital needs due to our active exploration,development and acquisition programs. Additional financing may be requiredin the future to fund our growth. We may not be able to obtain suchadditional financing, and financing under existing or new credit facilities may notbe 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’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONAND RESULTS OF OPERATIONS –*LIQUIDITY AND CAPITAL RESOURCES*.”*

 

**High demand for fieldservices and equipment and the ability of suppliers to meet that demand may limitour ability to drill and produce our oil and natural gas properties.**

 

Due to current industry demands, well serviceproviders and related equipment and personnel are in short supply. This iscausing escalating prices, delays in drilling and other exploration activities,the possibility of poor services coupled with potential damage to downholereservoirs and personnel injuries. Such pressures will likely increase theactual cost of services, extend the time to secure such services and add costsfor damages due to any accidents sustained from the over use of equipment andinexperienced personnel.

 

**Government regulation and liability for environmental matters may adverselyaffect our business and results of operations.**

 

Oil and natural gas operations are subject tovarious federal, state and local government regulations, which may bechanged from time to time. Matters subject to regulation include dischargepermits for drilling operations, drilling bonds, reports concerning operations,the spacing of wells, unitization and pooling of properties and taxation. Fromtime to time, regulatory agencies have imposed price controls and limitationson production by restricting the rate of flow of oil and natural gas wellsbelow actual production capacity in order to conserve supplies of oil andnatural gas. There are federal, state and local laws and regulations primarilyrelating to protection of human health and the environment applicable to thedevelopment, production, handling, storage, transportation and disposal of oiland natural gas, by-products thereof and other substances and materialsproduced or used in connection with oil and natural gas operations. Inaddition, we may be liable for environmental damages caused by previousowners of property we purchase or lease. As a result, we may incursubstantial liabilities to third parties or governmental entities. We are alsosubject to changing and extensive tax laws, the effects of which cannot bepredicted. The implementation of new, or the modification of existing, laws orregulations could have a material adverse effect on us. See *ITEMS 1**AND 2.* “*BUSINESS AND PROPERTIES –*INDUSTRY REGULATIONS.”

 

**We may have difficulty managing any future growth and the relateddemands on our resources and may have difficulty in achieving futuregrowth.**

 

We have experienced growth in the past through theexpansion of our drilling program and, more recently, acquisitions. Thisexpansion was curtailed in 1998 and 1999, but resumed in 2000 and increased insubsequent years. Further expansion is anticipated in 2006 both throughincreased drilling efforts and possible acquisitions. Any future growth may placea significant strain on our financial, technical, operational andadministrative resources. Our ability to grow will depend upon a number offactors, including our ability to identify and acquire new exploratoryprospects, our ability to develop existing prospects, our ability to continueto retain and attract skilled personnel, the results of our drilling programand acquisition efforts, hydrocarbon prices and access to capital. We may notbe successful in achieving or managing growth and any such failure could have amaterial adverse effect on us.

 

**We face strong competition from larger oil and naturalgas companies.**

 

The oil and gas industry is highly competitive. Weencounter competition from oil and natural gas companies in all areas of ouroperations, including the acquisition of exploratory prospects and productiveoil and natural gas properties. Our competitors range in size from the majorintegrated oil and natural gas companies to numerous independent oil andnatural gas companies, individuals and drilling and income programs. Many ofthese competitors are large, well-established companies with substantiallylarger operating staffs and greater capital resources than ours. We may notbe able to conduct our operations successfully, evaluate and select suitable 

 

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properties,consummate transactions, and obtain technical, managerial and otherprofessional personnel in this highly competitive environment. Specifically,these larger competitors may be able to pay more for exploratoryprospects, productive oil and natural gas properties and competent personneland may be able to define, evaluate, bid for and purchase a greater numberof properties and prospects than our financial or human resources permit. Inaddition, such competitors may be able to expend greater resources on theexisting and changing technologies that we believe are and will be increasinglyimportant to attaining success in the industry. Such competitors may alsobe in a better position to secure oilfield services and equipment on a timelybasis or on favorable terms. See*ITEMS 1 AND 2. “BUSINESS AND PROPERTIES –*COMPETITION.”

 

**The oil and natural gas reserve data included in or incorporated byreference in this document are estimates based on assumptions that may beinaccurate and existing economic and operating conditions that may differfrom future economic and operating conditions.**

 

Reservoir engineering is a subjective and inexactprocess of estimating underground accumulations of oil and natural gas thatcannot be measured in an exact manner and is based upon assumptions that may varyconsiderably from actual results. Accordingly, reserve estimates may besubject to downward or upward adjustment. Actual production, revenue andexpenditures with respect to our reserves will likely vary from estimates, andsuch variances may be material. The information regarding discountedfuture net cash flows included in this report should not be considered as thecurrent market value of the estimated oil and natural gas reserves attributableto our properties. As required by the SEC, the estimated discounted future netcash flows from proved reserves are based on prices and costs as of the date ofthe estimate, while actual future prices and costs may be materiallyhigher or lower. Actual future net cash flows also will be affected by factorssuch as the amount and timing of actual production, supply and demand for oiland natural gas, increases or decreases in consumption, and changes ingovernmental regulations or taxation. In addition, the 10% discount factor,which is required by Financial Accounting Standards Board in Statement ofFinancial Accounting 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 ineffect from time to time and risks associated with us or the oil and naturalgas industry in general. See *ITEMS 1 AND 2*. “*BUSINESS AND PROPERTIES –*OIL AND NATURAL GAS RESERVES.”

 

**Our credit facility has substantial operating restrictions andfinancial covenants and we may have difficulty obtaining additionalcredit, which could adversely affect operations.**

 

Over the past few years, increases in commodityprices, in proved reserve amounts and the resultant increase in estimateddiscounted future net revenue, has allowed us to increase our availableborrowing amounts. In the future, commodity prices may decline, we may increaseour borrowings or our borrowing base may be adjusted downward. Our creditfacility is secured by a pledge of substantially all of our assets and hascovenants that limit additional borrowings, sales of assets and thedistributions of cash or properties and that prohibit the payment of dividendsand the incurrence of liens. The revolving credit facility also requires thatspecified financial ratios be maintained. The restrictions of our creditfacility and the difficulty in obtaining additional debt financing may haveadverse consequences on our operations and financial results, including ourability to obtain financing for working capital, capital expenditures, ourdrilling program, purchases of new technology or other purposes. In addition,such financing may be on terms unfavorable to us and we may berequired to use a substantial portion of our cash flow to make debt servicepayments, which will reduce the funds that would otherwise be available foroperations and future business opportunities. Further, a substantial decreasein our operating cash flow or an increase in our expenses could make itdifficult for us to meet debt service requirements and require us to modifyoperations and we may become more vulnerable to downturns in our businessor the economy generally.

 

Our ability to obtain and service indebtedness willdepend on our future performance, including our ability to manage cash flow andworking capital, which are in turn subject to a variety of factors beyond ourcontrol. Our business may not generate cash flow at or above anticipatedlevels or we may not be able to borrow funds in amounts sufficient to enableus to service indebtedness, make anticipated capital expenditures or financeour drilling program. If we are unable to generate sufficient cash flow fromoperations or to borrow sufficient funds in the future to service our debt, we may berequired to curtail portions of our drilling program, sell assets, reducecapital expenditures, refinance all or a portion of our existing debt or obtainadditional financing. We may not be able to refinance our debt or obtainadditional financing, particularly in view of current industry conditions, therestrictions on our ability to incur debt under our existing debt arrangements,and the fact that substantially all of our assets are currently pledged tosecure obligations under our bank credit facility. See*ITEM 7. “MANAGEMENT’S*

 

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*DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION ANDRESULTS OF OPERATIONS**–***LIQUIDITY AND CAPITAL RESOURCES” and “–*CREDIT FACILITY.”*

 

**We may not have enough insurance to cover all of the risks weface.**

 

In accordance withcustomary industry practices, we maintain insurance coverage against some, butnot all, potential losses in order to protect against the risks we face. We donot carry business interruption insurance. We may elect not to carryinsurance if our management believes that the cost of available insurance isexcessive relative to the risks presented. In addition, we cannot insure fullyagainst pollution and environmental risks. The occurrence of an event not fullycovered by insurance could have a material adverse effect on our financialcondition and results of operations.

 

**Our acquisition program may be unsuccessful.**

 

Acquisitions have become increasingly important toour business strategy in recent years. The successful acquisition of producingproperties requires an assessment of recoverable reserves, future oil andnatural gas prices, operating costs, potential environmental and otherliabilities 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 inspectionson every well, and may not be able to observe structural and environmentalproblems even when we undertake an inspection. Even when problems areidentified, the seller may be unwilling or unable to provide effectivecontractual protection against all or part of such problems. Any acquisitionof property interests by us may not be successful and, if unsuccessful,such failure may have an adverse effect on our future results ofoperations and financial condition.

 

**We do not intend to pay dividends and our ability to pay dividends isrestricted.**

 

We currently intend to retain any earnings for thefuture operation and development of our business and do not currentlyanticipate paying any dividends in the foreseeable future. We are currentlyrestricted from paying dividends by our existing credit facility agreement. Anyfuture dividends also may be restricted by our then-existing loanagreements. See *ITEM 7. “MANAGEMENT’S DISCUSSION ANDANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS*–LIQUIDITY AND CAPITAL RESOURCES”and Note 10 to our consolidated financial statements.

 

**Our reliance on third parties for gathering and distributing couldcurtail future exploration and production activities.**

 

The marketability of our production depends upon theproximity of our reserves to, and the capacity of, third-party facilities andservices, including oil and natural gas gathering systems, pipelines, truckingor terminal facilities, and processing facilities. The unavailability or lackof capacity of such services and facilities could result in the shut-in ofproducing wells or the delay or discontinuance of development plans forproperties. A shut-in or delay or discontinuance could adversely affect ourfinancial condition. In addition, federal and state regulation of oil andnatural gas production and transportation affect our ability to produce andmarket our oil and natural gas on a profitable basis.

 

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

 

Our Certificate of Incorporation and Bylaws and theDelaware General Corporation Law contain provisions that may have theeffect of delaying, deferring or preventing 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 withstockholders with 15% or more of outstanding voting stock.

 

Because of these provisions, persons consideringunsolicited tender offers or other unilateral takeover proposals may bemore likely to negotiate with our board of directors rather than pursuenon-negotiated takeover attempts. As a result, these provisions may makeit more difficult for our stockholders to benefit from transactions that areopposed by an incumbent board of directors.

 

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**Miller’s former use of Arthur Andersen LLP as itsindependent public accountants may limit your ability to seek potentialrecoveries from them related to their work.**

 

Arthur Andersen LLP, independent public accountants,audited the consolidated balance sheet of Miller and its subsidiary as of December 31,2001, and the related consolidated statements of operations, equity and cashflows for the year ending December 31, 2001. On June 15, 2002, ArthurAndersen was convicted on a federal obstruction of justice charge, which wasoverturned in 2005. On June 27, 2002, Miller dismissed Arthur Andersen andengaged Plante & Moran, PLLC. Arthur Andersen has ceased operationsshortly after the conviction. As a result, any recovery any Edge stakeholder may havefrom Arthur Andersen related to the claims that such stakeholder may assertrelated to the financial statements audited by Arthur Andersen, misstatementsor omissions, if any, in this Form 10-K, will be limited by the financialcircumstances of Arthur Andersen.

 

***ITEM 1B. UNRESOLVED STAFF COMMENTS***

 

None.

 

23

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**CERTAIN DEFINITIONS**

 

The definitions set forth below shall apply to theindicated terms as used in this Annual Report. 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.

 

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

 

*Bbl.*Onestock tank barrel, or 42 U.S. gallons liquid volume, used herein in referenceto crude oil or other liquid hydrocarbons.

 

*Bbls/d.*Stocktank barrels per day*.*

 

*Bcf*. Billioncubic feet.

 

*Bcfe*. Billioncubic feet equivalent, determined using the ratio of six Mcf of natural gas toone Bbl of crude oil, condensate or natural gas liquids.

 

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

 

*Completion.*Theinstallation of permanent equipment for the production of oil or natural gasor, in the case of a dry hole, the reporting of abandonment to the appropriateagency.

 

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

 

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

 

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

 

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

 

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

 

*Field.*Anarea consisting of a single reservoir or multiple reservoirs all grouped on orrelated to the same individual geological structural feature and/orstratigraphic condition.

 

*Finding costs*.Costs associated with acquiring and developing proved oil and natural gasreserves which 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.

 

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

 

*MBbls*. Onethousand barrels of crude oil or other liquid hydrocarbons.

 

*Mcf.*Onethousand cubic feet.

 

*Mcf/d*. Onethousand cubic feet per day.

 

24

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*Mcfe.*Onethousand cubic feet equivalent determined using the ratio of six Mcf of naturalgas to one Bbl of crude oil, condensate or natural gas liquids, whichapproximates the relative energy content of crude oil, condensate and naturalgas 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.*Onemillion cubic feet.

 

*MMcf/d.*Onemillion cubic feet per day.

 

*MMcfe.*Onemillion cubic feet equivalent determined using the ratio of six Mcf of naturalgas to one Bbl of crude oil, condensate or natural gas liquids, whichapproximates the relative energy content of crude oil, condensate and naturalgas liquids as compared to natural gas.

 

*MMcfe/d.*Onemillion cubic feet equivalent per day.

 

*Net acres*or*net wells*. The sum of the fractional working interestsowned in gross acres or gross wells.

 

*NGL’s*. Naturalgas liquids measured in barrels.

 

*NRI*or*Net Revenue Interests*. The share of production aftersatisfaction of all royalty, overriding royalty, oil payments and other nonoperatinginterests.

 

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

 

*Over-pressured reservoirs*. Reservoirs subject to abnormally high pressure as a result of certaintypes of subsurface formations.

 

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

 

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

 

*Productive well*.A well that is found to be capable of producing hydrocarbons in sufficientquantities such that proceeds from the sale of such production exceedsproduction expenses and taxes.

 

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

 

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

 

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

 

*Proved reserves*.The estimated 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.

 

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

 

25

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*Proved undeveloped 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.*Thecompletion for production of an existing well bore in another formation fromthat in which the well has been previously completed.

 

*Reservoir.*Aporous and permeable underground formation containing a natural accumulation ofproducible oil and/or natural gas that is confined by impermeable rock or waterbarriers and is individual and separate from other reservoirs.

 

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

 

*3-D seismic*. 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.

 

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

 

*Working interest*or*WI.*The operating interest that gives the owner the rightto drill, produce and conduct operating activities on the property and a shareof production.

 

*Workover.*Operationson a producing well to restore or increase production.

 

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***ITEM 3. LEGAL PROCEEDINGS***

 

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

 

**TexasComptroller Audit**- During the second quarter of 2004, we received notice that our 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 maintainedthat transfers by the parent company to its subsidiaries that we classified asintercompany loans should instead be classified as equity investments in thesubsidiary. The State of Texas originally proposed that the franchise taxliability of the subsidiaries would be increased by approximately $3.0 millionfor the four-year period under audit.

 

Duringthe third quarter of 2004, the agent reduced the proposed franchise taxdeficiency adjustment to us to an aggregate of $467,000. In the fourth quarterof 2004, there was an informal hearing at the local Comptroller’s Office duringwhich the agent indicated he would formally assess the proposed deficiency. On March 24,2005, we received such deficiency assessment in the amount of $471,482including penalty and interest. We responded on April 21, 2005 with arequest for a formal redetermination hearing. On February 14, 2006, aHearings Attorney for the Texas Comptroller of Public Accounts issued aPosition Letter reaffirming the auditor’s assessment, and rejecting ourarguments as set forth in our April 21, 2005 request for redetermination.On February 24, 2006, we filed a motion to set the matter for oral hearingbefore an Administrative Law Judge. Prior to the oral hearing, we will submitadditional written materials to the Hearings Attorney. We intend to continue tovigorously contest the assessment through appropriate administrative levels inthe Comptroller’s Office and any other available means. Due to our intention tocontinue to vigorously contest the proposed adjustments, we have not recognizedany provision for the additional franchise taxes that would result from theproposed deficiency.

 

**Wade and Joyce Montet, et al., v.Edge Petroleum Corp of Texas, et al., consolidated with Rolland L. Broussard,et al., v. Edge Petroleum Corp of Texas, et al.**-**This is a consolidated suit, filed in statecourt in Vermilion Parish, Louisiana in September 2003 by two groups ofplaintiffs against Anadarko E&P Company, Norcen Explorer, Inc., UnionPacific Resources Company, Pan Canadian Petroleum Corporation, Japex (U.S.)Corporation, Vale Energy Corporation, Devon Louisiana Corporation and EdgePetroleum Exploration Company (one of our wholly-owned subsidiaries).Plaintiffs are mineral/royalty owners under the Norcen-Broussard No. 1 and2 wells, Marg Tex Reservoir C, Sand Unit A (herein the “MT RC SUA”, our BayouVermilion Prospect). They claim the operator at the time, Norcen Explorer, nowAnadarko, failed to “block squeeze” the sections of the No. 2 well, aswould a prudent operator, to protect the gas reservoir from being flooded withwater from adjacent underground formations. Plaintiffs further allege Norcenwas negligent in not creating a field-wide unit to protect their interests.Plaintiffs have named us and other working interest owners in the leases asdefendants, including Norcen Explorer’s successors in interest, Anadarko.Plaintiffs seek unspecified damages for lost royalties and damages due toalleged devaluation of their mineral and property interests, plus interest andattorneys’ fees. In early 2005, we filed a motion for summary judgment in thecase asserting, among other defenses, that: (i) there has been no breach of contract, (ii) there is noexpress or implied duty imposed on us to block squeeze the well or form afield-wide unit, (iii) the units were properly formed by the ConservationCommissioner in accordance with the statutory scheme in Louisiana, (iv) plaintiffs’claims are barred by limitations, and (v) other defenses. Along with theother defendants, we also filed a special preemptory challenge of no cause ofaction under the leases and the Louisiana Mineral Code for failure to exhaustadministrative remedies and due to lack of a demand. In May and June, 2005,the court ruled against us on the motion for summary judgment and thepreemptory challenges. Of the 18.75% after-payout working interest that we originallyreserved in the leases, we owned 2.8% working interest at the time of the allegedacts or omissions. On September 6, 2005, we were granted leave by thecourt to file a third party demand to join the other working interest ownerswho hold the remainder of the 18.75% working interest as direct defendants inthis case, and those pleadings have been served on the parties.

 

As of the date of this report, it is not possible todetermine what, if any, our exposure might be in this matter. The plaintiffs’expert witness, in his December 2005 deposition, offered his theory thatplaintiffs’ gross damages are in the range of $19 to 20 million. That number isbased on his theory that the alleged failure to block squeeze the well resultedin the under-production of gas worth $300 million. Plaintiffs’ royalty share ofthat figure yields the $19 to $22 million range of alleged damages. Based on theexpert’s testimony, damages attributable to the full 18.75% interest would bein the range of $3.75 million gross or net to our 2.8% share would be in therange of 

 

27

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$560,000(excluding interest and attorneys’ fees). Along with the other defendants, wehired our own expert witnesses who have refuted these claims, particularly theexpert’s assertions that failure to block squeeze the well caused any damagesto the reservoir. There is currently a trial setting in the case of May 22,2006.

 

Wemay have insurance coverage for all or part of this claim up to the $2.0million limits of the policy. A claim was submitted to our casualty carrier,who is currently providing a defense under a reservation of rights letter. We believethat we would only be liable for our 2.8%share of any damage award unless a co-party defendant cannot satisfy its shareof any final judgment. We intend to continue to vigorously contest thissuit. We have not established any reserve with respect to these claims.

 

***ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS***

 

NONE.

 

**Executive Officers of the Registrant**

 

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

 

**John W. Elias**has served as the Chief Executive Officer and Chairman of the Board of theCompany 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 pipeline marketing. Priorto April 1993, Mr. Elias served in various positions for more than 30years, including senior management positions with Amoco Corporation, a majorintegrated oil and gas company. Mr. Elias has more than 40 years ofexperience in the oil and natural gas exploration and production business. Heis 65 years old.

 

# **Michael G. Long** has served as Executive VicePresident and ChiefFinancial Officer of the Company since April 2005 and as Senior VicePresident and Chief Financial Officer since December 1996, and asTreasurer of the Company since October 2004. Mr. Long served as VicePresident-Finance of W&T Offshore, Inc., an oil and natural gasexploration and production company, from July 1995 to December 1996. FromMay 1994 to July 1995, he served as Vice President of the SouthwestPetroleum Division for Chase Manhattan Bank, N.A. Prior thereto, he served invarious capacities with First National Bank of Chicago, most recently that ofVice President and Senior Corporate Banker of the Energy and TransportationDepartment, from March 1992 to May 1994. Mr. Long received aB.A. in Political Science and a M.S. in Economics from the University ofIllinois. Mr. Long is 53 years old.

 

**John O. Tugwell**has served as Chief Operating Officer and Executive Vice President since April 2005and prior to that served as Chief Operating Officer and Senior Vice Presidentof Production for the Company since March 2004 and prior to that as VicePresident of Production since March 1997. He served as Senior PetroleumEngineer of the Company’s predecessor corporation since May 1995. From 1986to May 1995, Mr. Tugwell held various reservoir/productionengineering positions with Shell Oil Company, most recently that of SeniorReservoir Engineer. Mr. Tugwell holds a B.S. in Petroleum Engineering fromLouisiana State University. Mr. Tugwell is a registered ProfessionalEngineer in the State of Texas. Mr. Tugwell is 42 years old.

 

**Significant Employees**

 

**Howard Creasey**has served as the Vice President of Exploration for the Company since October 2005and prior to that served as Chief Geologist for the Company since October 2003.From April of 1999 until October 2003 he served as a SeniorStaff Geologist for Devon Energy and its predecessor Ocean Energy. Priorto April 1999 for 14 years Howard served as Presidentand Exploration Geologist for Moss Rose Energy, Inc., a companyhe started in 1986. Mr. Creasey holds a B.S. in Geology from Stephen F.Austin State University, has been a member of the AAPG for over 25 years and isa Certified Geoscientist in the State of Texas.  Mr. Creaseyis 50 years old.

 

**Mark J. Gabrisch**has served as Senior Vice President of Land for the Company since September 2005and prior to that served as Vice President of Land since March 1997. From November 1994to March 1997, he served in a similar capacity with the Company’s predecessorcorporation. From 1985 to October 1994, he was a landman, most 

 

28

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recentlya Senior Landman, for Shell Oil Company. Mr. Gabrisch holds a B.S. inPetroleum Land Management from the University of Houston. Mr. Gabrisch is45 years old.

 

**Kirsten A. Hink**hasserved as Vice President & Controller of the Company since October 1,2003 and as Controller of the Company since December 31, 2000. Prior tothat time she served as Assistant Controller from June 2000 to December 2000.Before joining Edge, she served as Controller of Benz Energy Inc., an oil andgas exploration company, from June 1998 to June 2000. Mrs. Hinkreceived a B.S. in Accounting from Trinity University. Mrs. Hink is aCertified Public Accountant in the State of Texas. She is 39 years old.

 

**James D.Keisling** has servedas Vice President of Production for the Company since April 2004. From May 2000to April 2004, he served as 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. Keislingholds a B.S. degree in Civil Engineering from New Mexico State University. Mr. Keislingis a registered professional engineer in the State of Texas. He is 58 yearsold.

 

**C.W. MacLeod**has served as the Senior Vice President BusinessDevelopment and Planning for the Company since April 2004 and VicePresident Business Development and Planning for the Company since January 2002.From November 1999 to December 2001, he was Vice President -Investment Banking with Raymond James and Associates, Inc. From February 1990to October 1999, Mr. MacLeod was a principal with Kirkpatrick EnergyAssociates, Inc., whose principal business was merger and acquisitionservices, capital arrangement and analytical services for the oil and gasproducing industry. Mr. MacLeod was responsible for originating corporatefinance and research products for energy clients. His previous experienceincludes positions as an independent petroleum geologist, a manager ofexploration and production for an independent oil and gas producer and geologicpositions with Ladd Petroleum Corporation and Resource Sciences Corporation. Mr. MacLeodgraduated from Eastern Michigan University with a B.S. in Geology and earnedhis M.B.A. from the University of Tulsa. Mr. MacLeod is a registeredprofessional geologist in the State of Wyoming. He is 55 years old.

 

**Robert C. Thomas**has served as Vice President, General Counsel and Corporate Secretarysince March 1997. From February 1991 to March 1997, he served insimilar capacities for the Company’s corporate predecessor. From 1988 to January 1991,he was associate and acting general counsel for Mesa Limited Partnership inAmarillo, Texas. Mr. Thomas holds a B.S. degree in Finance and a J.D.degree in Law from the University of Texas at Austin. He is 52 years old.

 

29

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##### **PART II**

#####  

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

 

*Market Price of and Dividends on Common Equity and Related StockholderMatters.*

 

As of March 10, 2006, we estimate there wereapproximately 237 beneficial holders of our Common Stock. Our Common Stock islisted on the NASDAQ National Market (“NASDAQ”) and traded under the symbol “EPEX”.As of March 10, 2006, we had 17,239,679 shares outstanding and our closingprice on NASDAQ was $24.97 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 2005** |       |                              |       |   |   |
| First Quarter     |       | 18.24                             |       | 13.40 |   |
| Second Quarter    |       | 16.86                             |       | 12.46 |   |
| Third Quarter     |       | 27.94                             |       | 15.47 |   |
| Fourth Quarter    |       | 28.49                             |       | 20.05 |   |
|              |       |                              |       |   |   |
| **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 |   |

 

***We have never paid a dividend,cash or otherwise, and do not intend to in the foreseeable future. In addition,under our current credit facility, we are restricted from paying cash dividendson our Common Stock. The payment of future dividends, if any, will bedetermined by our Board of Directors in light of conditions then existing,including our earnings, financial condition, capital requirements, restrictionsin financing agreements, business conditions and other factors. See***ITEMS 1A. “RISK FACTORS– We donot intend to pay dividends and our ability to pay dividends is restricted.”

 

There were no repurchases of securities duringthe fourth quarter of 2005.

 

30

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***ITEM 6. SELECTED FINANCIAL DATA***

 

***The following table sets forthselected financial data regarding the Company as of and for each of the periodsindicated. The following data should be read in conjunction with***ITEM7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OFOPERATIONS” and ITEM 8. “FINANCIALS STATEMENTS AND SUPPLEMENTARY DATA”:

*** ***
| ** **                                                                            | ** ** | **Year Ended December 31,**                        | ** **  |
|---------------------------------------------------------------------------------------|------------|--------------------------------------------------------------|-------------|
| ** **                                                                            | ** ** | **2005(1)**                                                  | ** **  | **2004(2)** | ** ** | **2003 (3)** | ** ** | **2002** | ** ** | **2001 (4)** | ** ** |
| ** **                                                                            | ** ** | **(in thousands,  except per share amounts)** | ** **  |
| **Statement of operations:**                                                          |       |                                                         |        |   |   |   |   |   |   |   |   |
| Oil and  natural gas revenue                                                          | ** ** | **$**                                                        | **121,183** |   | $ | 64,505 |   | $ | 33,926 |   | $ | 20,911 |   | $ | 29,811 |   |
| Operating  expenses:                                                                  |       |                                                         | ** **  |   |   |   |   |   |   |   |   |
| Oil and  natural gas operating expenses including production and ad valorem taxes     | ** ** | **17,068**                                                   | ** **  | 9,309 |   | 5,116 |   | 3,831 |   | 5,001 |   |
| Depletion,  depreciation, amortization and accretion (3)                              | ** ** | **40,218**                                                   | ** **  | 21,928 |   | 13,577 |   | 10,427 |   | 9,378 |   |
| Litigation  settlement                                                                | ** ** | **—**                                                   | ** **  | — |   | — |   | — |   | 3,547 |   |
| General and  administrative expenses:                                                 |       |                                                         | ** **  |   |   |   |   |   |   |   |   |
| Deferred  compensation expense – repriced options (5)                            | ** ** | **1,628**                                                    | ** **  | 1,136 |   | 1,219 |   | 4 |   | (850 | ) |
| Deferred  compensation expense – restricted stock                                | ** ** | **974**                                                      | ** **  | 498 |   | 372 |   | 399 |   | 353 |   |
| Other  general and administrative and bad debt expense                                | ** ** | **9,834**                                                    | ** **  | 7,813 |   | 5,541 |   | 4,826 |   | 5,038 |   |
| Total  operating expenses                                                             | ** ** | **69,722**                                                   | ** **  | 40,684 |   | 25,825 |   | 19,487 |   | 22,467 |   |
|                                                                                  | ** ** | ** **                                                   | ** **  |   |   |   |   |   |   |   |   |
| Operating  income                                                                     | ** ** | **51,461**                                                   | ** **  | 23,821 |   | 8,101 |   | 1,424 |   | 7,344 |   |
| Interest  expense and amortization of deferred loan costs, net of amounts capitalized | ** ** | **(153**                                                     | **)**       | (473 | ) | (679 | ) | (228 | ) | (215 | ) |
| Interest  income                                                                      | ** ** | **128**                                                      | ** **  | 36 |   | 17 |   | 27 |   | 128 |   |
| Income  before income taxes and cumulative effect of accounting change                | ** ** | **51,436**                                                   | ** **  | 23,384 |   | 7,439 |   | 1,223 |   | 7,257 |   |
| Income tax (expense) benefit                                                          | ** ** | **(18,078**                                                  | **)**       | (8,255 | ) | (2,731 | ) | (473 | ) | 819 |   |
| Income  before cumulative effect of accounting change                                 | ** ** | **33,358**                                                   | ** **  | 15,129 |   | 4,708 |   | 750 |   | 8,076 |   |
| Cumulative effect of accounting change (3)                                            | ** ** | **—**                                                   | ** **  | — |   | (358 | ) | — |   | — |   |
| Net income                                                                            | ** ** | **$**                                                        | **33,358**  | ** ** | $ | 15,129 |   | $ | 4,350 |   | $ | 750 |   | $ | 8,076 |   |
|                                                                                  |       |                                                         | ** **  |   |   |   |   |   |   |   |   |
| Basic  earnings per share:                                                            |       |                                                         | ** **  |   |   |   |   |   |   |   |   |
| Income  before cumulative effect of accounting change                                 | ** ** | **$**                                                        | **1.95**    | ** ** | $ | 1.16 |   | $ | 0.48 |   | $ | 0.08 |   | $ | 0.87 |   |
| Cumulative  effect of accounting change                                               | ** ** | **—**                                                   | ** **  | — |   | (0.03 | ) | — |   | — |   |
| Basic  earnings per share                                                             | ** ** | **$**                                                        | **1.95**    | ** ** | $ | 1.16 |   | $ | 0.45 |   | $ | 0.08 |   | $ | 0.87 |   |
|                                                                                  |       |                                                         | ** **  |   |   |   |   |   |   |   |   |
| Diluted  earnings per share:                                                          |       |                                                         | ** **  |   |   |   |   |   |   |   |   |
| Income  before cumulative effect of accounting change                                 | ** ** | **$**                                                        | **1.87**    | ** ** | $ | 1.11 |   | $ | 0.47 |   | $ | 0.08 |   | $ | 0.83 |   |
| Cumulative  effect of accounting change (3)                                           | ** ** | **—**                                                   | ** **  | — |   | (0.03 | ) | — |   | — |   |
| Diluted  earnings per share                                                           | ** ** | **$**                                                        | **1.87**    | ** ** | $ | 1.11 |   | $ | 0.44 |   | $ | 0.08 |   | $ | 0.83 |   |
|                                                                                  | ** ** | ** **                                                   | ** **  |   |   |   |   |   |   |   |   |
| Basic  weighted average number of shares outstanding (6)                              | ** ** | **17,122**                                                   | ** **  | 13,029 |   | 9,726 |   | 9,384 |   | 9,281 |   |
| Diluted  weighted average number of shares outstanding (6)                            | ** ** | **17,815**                                                   | ** **  | 13,648 |   | 9,988 |   | 9,606 |   | 9,728 |   |
| ** **                                                                            |       |                                                         | ** **  |   |   |   |   |   |   |   |   |
| **EBITDA  Reconciliation (7):**                                                       |       |                                                         | ** **  |   |   |   |   |   |   |   |   |
| Net income                                                                            | ** ** | **$**                                                        | **33,358**  | ** ** | $ | 15,129 |   | $ | 4,350 |   | $ | 750 |   | $ | 8,076 |   |
| Cumulative  effect of accounting change (3)                                           | ** ** | **—**                                                   | ** **  | — |   | 358 |   | — |   | — |   |
| Income tax  expense (benefit)                                                         | ** ** | **18,078**                                                   | ** **  | 8,255 |   | 2,731 |   | 473 |   | (819 | ) |
| Interest  expense and amortization of deferred loan costs, net of amounts capitalized | ** ** | **153**                                                      | ** **  | 473 |   | 679 |   | 228 |   | 215 |   |
| Interest  income                                                                      | ** ** | **(128**                                                     | **)**       | (36 | ) | (17 | ) | (27 | ) | (128 | ) |
| Depletion,  depreciation, amortization and accretion (3)                              | ** ** | **40,218**                                                   | ** **  | 21,928 |   | 13,577 |   | 10,427 |   | 9,378 |   |
|                                                                                  | ** ** | ** **                                                   | ** **  |   |   |   |   |   |   |   |   |
| **EBITDA**                                                                            | ** ** | **$**                                                        | **91,679**  | ** ** | $ | 45,749 |   | $ | 21,678 |   | $ | 11,851 |   | $ | 16,722 |   |

 

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| ** **                                    | ** ** | **As of December 31,** | ** **   |
|-----------------------------------------------|------------|---------------------------------------|--------------|
| ** **                                    | ** ** | **2005 (1)**                     | ** **   | **2004 (2)** | ** ** | **2003 (3)** | ** ** | **2002** | ** ** | **2001 (4)** | ** ** |
| ** **                                    | ** ** | **(in thousands)**               | ** **   |
| ** **                                    |       |                                  |         |   |   |   |   |   |   |   |   |
| **Selected Cash Flow Data:**                  |       |                                  |         |   |   |   |   |   |   |   |   |
| Net cash provided by operating activities     | ** ** | **$**                                 | **93,110**   |   | $ | 42,270 |   | $ | 23,898 |   | $ | 10,408 |   | $ | 22,151 |   |
|                                          |       |                                  |         |   |   |   |   |   |   |   |   |
| Net cash used in investing activities         | ** ** | **$**                                 | **(167,279** | **)** | $ | (89,410 | ) | $ | (28,070 | ) | $ | (19,255 | ) | $ | (28,989 | ) |
|                                          | ** ** | ** **                            |         |   |   |   |   |   |   |   |   |
| Net cash provided by financing activities     | ** ** | **$**                                 | **72,568**   |   | $ | 48,080 |   | $ | 2,931 |   | $ | 10,623 |   | $ | 7,383 |   |
|                                          |       |                                  |         |   |   |   |   |   |   |   |   |
| **Selected Balance Sheet Data:**              |       |                                  |         |   |   |   |   |   |   |   |   |
| ** **                                    |       |                                  |         |   |   |   |   |   |   |   |   |
| Working capital (8)                           | ** ** | **$**                                 | **10,537**   |   | $ | 8,957 |   | $ | 948 |   | $ | 3,310 |   | $ | 682 |   |
| Property and equipment, net                   | ** ** | **306,456**                           |         | 165,840 |   | 97,981 |   | 75,682 |   | 66,853 |   |
|                                          | ** ** | ** **                            |         |   |   |   |   |   |   |   |   |
| Total assets                                  | ** ** | **343,380**                           |         | 190,990 |   | 118,012 |   | 85,576 |   | 76,024 |   |
| Long-term debt, including current  maturities | ** ** | **85,000**                            |         | 20,000 |   | 21,000 |   | 20,500 |   | 10,000 |   |
| Stockholders’ equity (6)                 | ** ** | **191,755**                           |         | 150,467 |   | 82,011 |   | 58,533 |   | 58,099 |   |

 

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(1)                  As discussed inNote 6 to our consolidated financial statements, we completed one propertyacquisition and one corporate acquisition in the fourth quarter of 2005, whichaffects the comparability of our results in 2005 to prior periods.

 

(2)                  As discussed inNote 6 to our consolidated financial statements, we completed the merger withMiller in December 2003, which affects the comparability of our results in2004, and subsequent periods, to prior periods.

 

(3)                  As discussed in Note 2 to ourconsolidated financial statements, effective January 1, 2003, we changedour method of accounting for asset retirement obligations, which affects thecomparability of our results in 2003, and subsequent periods, to prior periods.

 

(4)                  As discussed inNote 2 to our consolidated financial statements, effective January 1,2001, we changed our method of accounting for derivative instruments, whichaffects the comparability of our results in 2001 to subsequent periods due totransition adjustments recorded in 2001.

 

(5)                  Deferredcompensation expense includes the non-cash charge or credit related to FASB InterpretationNo. (“FIN”) 44, “*Accounting for CertainTransactions involving Stock Compensation.”*In May 1999,certain of our 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. Volatilityin our stock price can have a significant impact on this amount, which may affectthe comparability of our results for the periods presented.

 

(6)                  As discussed inNote 11 to our consolidated financial statements, we completed a publicoffering of our common stock on December 21, 2004 and a significant property acquisition on December 29, 2004,therefore certain of our results in 2004 and subsequent periods are notdirectly comparable to periods prior to 2004.

 

(7)                  EBITDA is defined as net income (loss) beforecumulative effect of accounting change, interest expense and amortization ofdeferred loan costs (net of interest income and amounts capitalized), incometax expense, depletion, depreciation and amortization and accretion expense.EBITDA is a financial measure commonly used in the oil and natural gasindustry, but is not defined under accounting principles generally accepted inthe United States of America (“GAAP”). EBITDA should not be considered inisolation or as a substitute for net income, operating income, cash flows fromoperating activities or any other measure of financial performance presented inaccordance with GAAP or as a measure of a company’s profitability or liquidity.Because EBITDA excludes some, but not all, items that affect net income, thismeasure may vary among companies. The EBITDA data presented above may notbe comparable to a similarly titled measure of other companies. Our managementbelieves that EBITDA is a meaningful measure to investors and provides additionalinformation about our ability to meet our future liquidity requirements fordebt service, capital expenditures and working capital. In addition, managementbelieves that EBITDA is a useful comparative measure of operating performanceand liquidity. For example, debt levels, credit ratings and, therefore, theimpact of interest expense on earnings vary significantly between companies.Similarly, the tax positions of individual companies can vary because of theirdiffering abilities to take advantage of tax benefits, with the result thattheir effective tax rates and tax expense can vary considerably. Finally,companies differ in the age and method of acquisition of productive assets, andthus the relative costs of those assets, as well as in the depreciation ordepletion (straight-line, accelerated, units of production) method, which canresult in considerable variability in depletion, depreciation and amortizationexpense between companies. Thus, for comparison purposes, management believesthat EBITDA can be useful as an objective and comparable measure of operatingprofitability and the contribution of operations to liquidity because itexcludes these elements.

 

(8)                  Working Capital is defined as current assetsless current liabilities.

 

We do not pay cash dividends and have not in the periods presentedabove, therefore they are not presented in the selected financial data.

 

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***ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS OF OPERATIONS***

 

The following is a review of our financial positionand results of operations for the periods indicated. 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 of Financial Condition and Results of Operations (“MD&A”).

 

**GENERAL OVERVIEW**

 

Edge Petroleum Corporation (“Edge”,“we” or the “Company”) is a Houston-based independent energy company thatfocuses its exploration, development, production, acquisition and marketingactivities in selected onshore basins of the United States. In late 1998, weundertook a top-level management change and began a shift in strategy from pureexploration, which focused more on prospect generation, to our current strategywhich focuses on a balanced program of exploration, exploitation anddevelopment and acquisition of oil and gas properties. We generate revenues,income and cash flows by producing and marketing oil and natural gas producedfrom our oil and natural gas properties. We make significant capitalexpenditures in our exploration, development, and acquisition activities thatallow us to continue generating revenue, income and cash flows.

 

This overview provides our perspective on theindividual sections of MD&A, as well as helpful hints for reading thesepages. Our MD&A includes the following sections:

 

•                  **Industry and Economic Factors** – a general description of value drivers ofour business as well as opportunities, challenges and risks related to the oiland gas industry.

 

•                  **Approach to the Business** – additional information regarding ourapproach and strategy.

 

•                  **Acquisitions and Divestitures** – information about significant changes inour business structure.

 

•                  **Outlook** – additional discussion relating to management’s outlook to the futureof our business.

 

•                  **Critical Accounting Policies and Estimates** – a discussion of certain accountingpolicies that require critical judgments and estimates.

 

•                  **Results of Operations** – an analysis of our consolidated resultsfor the periods presented in our financial statements.

 

•                  **Liquidity and Capital Resources –**an analysis of cash flows, sources and usesof cash, and contractual obligations.

 

•                  **Risk Management Activities – Derivatives &Hedging –**supplementaryinformation regarding our price-risk management activities involving commoditycontracts that are accounted for at fair value.

 

•                  **Tax Matters** – supplementary discussion of income tax matters.

 

•                  **Recently Issued Accounting Pronouncements** – a discussion of certain recently issued accountingpronouncements that may impact our future results.

 

# **INDUSTRYAND ECONOMIC FACTORS**

 

In managing our business, we must deal with manyfactors inherent in our industry. First and foremost is the fluctuation of oiland gas prices. Historically, oil and gas markets have been cyclical andvolatile, which makes future price movements difficult to predict. While ourrevenues are a function of both production and prices, wide swings in commodityprices have most often had the greatest impact on our results of operations. Wehave little 

 

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abilityto predict those prices or to control them without losing some advantage of theupside potential. The oil and gas industry has experienced a high commodityprice environment in 2005, which has positively impacted the entire industry aswell as our Company. Although prices have begun to decrease since year-end2005, they remain at historically high levels.

 

Our operations entail significant complexities. Advancedtechnologies requiring highly trained personnel are utilized in bothexploration and production. Even when the technology is properly used, we may stillnot know conclusively if hydrocarbons will be present or the rate at which theywill be produced. Exploration is a high-risk activity, often times resulting inno commercially productive reserves being discovered. Moreover, costsassociated with operating within our industry are substantial. The recent highcommodity price environment has also led to increased costs in our industry,which together with increased demand for rigs, equipment, supplies and services,have made it difficult at times for us to further our growth, and made timelyexecution of our planned activities difficult.

 

Our business, as with other extractive businesses,is a depleting one in which each gas equivalent produced must be replaced or ourasset base and capacity to generate revenues in the future will shrink.

 

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

 

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

 

During the third quarter 2005, Hurricanes Rita andKatrina hit the Gulf Coast causing damage to many of the platforms in the Gulfof Mexico, as well as numerous onshore facilities related to our industry. As aresult, both oil and natural gas prices increased in late August. We werefortunate to avoid substantial damage or major interruptions in our productionor business, but were forced to shut-in several of our larger wells inMississippi due to the inability of trucks to gain access to haul the crude oilproduction from the wells. We also were forced to close our corporate officesfor several days to allow our Houston-based employees to evacuate.

 

# **APPROACHTO THE BUSINESS**

 

Profitable growth of our business will largelydepend upon our ability to successfully find and develop new proved reserves ofoil and natural gas in a cost-effective manner. In order to achieve an overallacceptable rate of growth, we seek to maintain a prudent blend of low-,moderate- and higher-risk exploration and development projects. We have chosento seek geologic and geographic diversification by operating in multiple basinsin order to mitigate risk in our operations. We also attempt to make selectedacquisitions of oil and gas properties to augment our growth and provide futuredrilling opportunities. We periodically hedge our exposure to volatile oil andgas prices on a portion of our production to reduce price risk. As of December 31,2005, we have entered into hedge contracts covering approximately 48% and 37% ofour anticipated 2006 natural gas and crude oil production, respectively, beforeany future acquisitions. In 2005, we had 51% and 33% of natural gas and crudeoil production, respectively, hedged.

 

Implementation of our business approach relies onour ability to fund ongoing exploration and development projects with cash flowprovided by operating activities and external sources of capital. In recentyears we have been able to expand our capital budget during the year as aresult of our drilling successes and acquisition program. Our Board recentlyapproved a 2006 capital budget of approximately $98 million. Based on currentexpectations for production volumes and commodity prices, we expect to fundthose capital expenditures from internally generated cash from operatingactivities, as well as modestly reduce our debt levels. We do not typicallyinclude acquisitions in our budgeted capital expenditures, but expect to fundthose with either borrowings under our credit facility, proceeds from offeringsof common stock or other securities under our shelf registration statement orother sources.

 

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For 2005, we reported a 15% increase in proved reservesover the 2004 period, including the effect of the Chapman Ranch Field acquisitions(see “-Acquisitions and Divestitures” below), and a 35% increase in annualproduction volumes over the 2004 period. We also replaced 184% of our total 2005reserves (see *ITEMS 1 AND 2. “BUSINESS ANDPROPERTIES*– OIL AND NATURAL GAS RESERVE REPLACEMENT.” Production inthe fourth quarter of 2005 was 11% higher than in the previous quarter and weexited 2005 with a record daily production rate of 51.7 MMcfe/d as compared to 49.1MMcfe/d a year ago. We believe that we are currently in a strong financialposition, as represented by a debt to total capital ratio of 30.7%, availableunused borrowing capacity of $25 million at December 31, 2005 andincreased cash flow from our growing production volumes as a result ofsuccessful drilling and the Chapman Ranch Field acquisitions completed in thefourth quarter of 2005 that will help lay the ground work for our activities in2006. Operationally and financially, we believe we are well positioned tocontinue the execution of our business strategy during 2006.

 

**ACQUISITIONS AND DIVESTITURES**

 

*Acquisitions*- We have becomeincreasingly active in acquisitions in recent years. We have looked toacquisitions to enable us to achieve our growth objectives and we expectacquisitions will continue to play a significant role in our future plans forgrowth. Acquisitions add meaningful incremental increases in reserves andproduction and may range in size from acquiring a working interest innon-operated producing property to an entire field or company. Unlike drillingcapital, which is planned and budgeted, acquisition capital is not budgeted. Specifictiming of acquisitions cannot be predicted. Although we consider a wide varietyof acquisitions, a significant part of our growth strategy is expected tobe focused toward producing property acquisitions, which we believe haveexploitable potential. Because of our financial flexibility, we are positionedto take advantage of opportunities to acquire producing properties as they may arise.In today’s high-price environment, where production is providing greater cashflow and earnings to most companies in our industry, identifying qualityopportunities is difficult. We believe through hard work, technical ability andcreative thinking, we will continue to grow through both acquisitions anddrilling. Any such acquisition could involve the payment by us of a substantialamount of cash or the issuance of a substantial number of additional shares orother securities.

 

On December 4, 2003, we completed ouracquisition of Miller Exploration Company (“Miller”). Miller was an independentoil and gas exploration and production company with exploration effortsconcentrated primarily in the Mississippi Salt Basin of central Mississippi. Underthe terms of the merger agreement, each share of issued and outstanding commonstock of Miller was converted into 1.22342 shares of Edge common stock. Weissued approximately 2.6 million shares of Edge common stock to the shareholdersof Miller in exchange for all of the outstanding common stock of Miller. Themerger was treated as a tax-free reorganization and accounted for as a purchasebusiness combination under generally accepted accounting principles. We operatethe majority of the acquired properties. We acquired Miller for the developmentand exploitation projects in Miller’s core area, increased financialflexibility, and expansion of our core areas. During 2005, we added to the landand seismic position in Mississippi acquired in the Miller merger and expect tosee an increase in operating activity on those properties in 2006.

 

OnOctober 7, 2004, we executed an Asset Purchase Agreement to acquire oiland natural gas properties located in south Texas from Contango Oil &Gas Company (“Contango”). The final cash purchase price for the acquisition was$40.1 million, which was adjusted from the original price of $50.0 million forthe results of operations between the July 1, 2004 effective date and the December 29,2004 closing date pursuant to the closing adjustment provisions. We financedthe acquisition with proceeds from a public offering of our common stock underour shelf registration (see Note 11 to our consolidated financial statements).The properties acquired consisted of 39 non-operated producing wells withworking 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 also identified a substantial number of additional drillinglocations on undeveloped acreage for which we realized much of the exploitablepotential in 2005. We view this area as a major growth area for the Company in2006.

 

OnSeptember 21, 2005, we executed two separate and definitive agreements (the“CRF Agreements”) for the acquisition of (i) the stock of a privatecompany, Cinco Energy Corporation (“Cinco”), whose primary asset is ownershipof working interests in oil and natural gas properties located on the ChapmanRanch Field in south Texas and (ii) additional working interests in thesame field owned by two other private companies for an aggregate cash purchaseprice of approximately $62.8 million (of which $35.8 million is attributable tothe stock purchase and 

 

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$27.0 million isattributable to the working interest asset purchase). We allocatedapproximately $17.5 million of the total purchase price to the unprovedproperty category. The properties acquired from these entities are located inNueces County, Texas and consist of eight non-operated producing wells, onewell undergoing completion operations, and one well shut in for evaluation, aswell as an ownership in approximately 1,300 net acres of developed andundeveloped leasehold as of the closing date of November 30, 2005.

 

Pursuantto the CRF Agreements, we agreed to pay the three sellers an aggregateincremental purchase price of $5.2 million (of which $3.0 million isattributable to the stock purchase and $2.2 million is attributable to theworking interest asset purchase) related to the operator obtaining high-costgas certification on or before January 31, 2006, which would provide forseverance tax abatements on the properties acquired. The aggregate incrementalpurchase price was reduced to $4.8 million in January 2006 because aportion of the properties did not qualify for high-cost gas certification. On November 30,2005, we paid a portion of the incremental purchase price of $3.9 million whena portion of the properties qualified for the certification and incurred acontingent liability for the remaining balance of $0.9 million, which was paidto the Sellers in the first quarter of 2006.

 

OnOctober 13, 2005, we consummated the Chapman Ranch Field assetacquisition. The cash base purchase price of $27.0 million was adjusted to $28.0million for the incremental purchase price (see above) and the results ofoperations between the September 1, 2005 effective date and the October 13,2005 closing date, pursuant to the closing adjustment provisions of the relevantagreement. On November 30, 2005, we consummated the Cinco stock purchase.The cash base purchase price at closing of $35.8 million was subject toadjustment for, among other things, working capital as of September 1,2005 and an incremental purchase price (see above), pursuant to the closingprovisions of the relevant agreement. The preliminarily adjusted purchase priceof Cinco was $47.3 million. We financed the acquisitions through borrowingsunder our credit facility, the borrowing base of which was increased inconnection with these transactions and other recent activities since the lastredetermination.

 

*Divestitures-*We regularly review our asset base forthe purpose of identifying non-core assets, the disposition of which wouldincrease capital resources available for other activities and createorganizational and operational efficiencies. While we generally do not disposeof assets solely for the purpose of reducing debt, such dispositions can havethe result of furthering our objective of financial flexibility through reduceddebt levels. During 2005, we had no divestitures. During 2004 and 2003, ourdivestitures consisted of the sales of oil and gas properties for net proceedsof $60,000 and $330,100, respectively. Our 2004 net proceeds from asset divestitureswere primarily derived from the sale of certain oil and gas properties andequipment in Texas, Mississippi and Louisiana. Our 2003 net proceeds from assetdivestitures were primarily derived from the sale of our interest in twoaffiliated entities, Essex I and II Joint Ventures, and certain oil and gasproperties in Texas and Louisiana.

 

**OUTLOOK**

 

•                  Wesuccessfully completed several acquisitions during 2005. We expect to continueto spend considerable effort in 2006 on acquisitions, as we seek to further ourgrowth.

•                  Weexpect to drill between 55 and 60 wells (32 and 35 net, respectively) in 2006and we estimate capital spending for the year to be approximately $98 million.Our ability to materially increase the number of wells to be drilled beyond ouroriginal budget number is heavily dependent upon the timely access to oilfieldservices, particularly drilling rigs. The shortage of available rigs in 2005 delayedthe drilling of several wells, slowing our growth in production.

•                  Ourexpected production volumes, including the addition of the Chapman Ranch Field properties,combined with the current commodity-pricing environment, is anticipated toproduce another year of record cash flow.

•                  During2005, we initiated activities via the purchase of undeveloped leasehold in theFayetteville Shale in Arkansas and Floyd Shale in Mississippi and Alabama. Bothof these projects are new focus areas.

•                  Inorder to manage our realized growth in 2005 and our anticipated growth for thenext several years, we increased our headcount from 51 employees as of December 31,2004 to 62 employees as of December 31, 2005 resulting in increasedG&A costs for 2005. We expect to add to our staff levels again in 2006 bothas a result of recent growth and anticipated future growth.

•                  Tohelp protect against the possibility of downward commodity price movements, wehave entered into several hedges covering approximately 48% of our expectednatural gas production and 37% of our expected crude oil production streams for2006.

 

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Our outlook and the expected results described aboveare both subject to change based upon factors that include, but are not limitedto, drilling results, commodity prices, access to capital, the acquisitions marketand factors referred to in “FORWARD LOOKING INFORMATION.”

 

**CRITICAL ACCOUNTING POLICIES AND ESTIMATES**

 

The preparation of financial statements inconformity with generally accepted accounting principles in the United Statesrequires management to make estimates and assumptions that affect the reportedamounts of assets, liabilities, revenues, expenses, contingent assets andliabilities and the related disclosures in the accompanying financialstatements. Changes in these estimates and assumptions could materially affectour financial position, results of operations or cash flows. Managementconsiders an accounting estimate to be critical if:

 

•                  itrequires assumptions to be made that were uncertain at the time the estimatewas made, and

 

•                  changesin the estimate or different estimates that could have been selected could havea material impact on our consolidated results of operations or financialcondition.

 

All other significant accounting policies thatwe employ are presented in the notes to the consolidated financial statements.The following discussion presents information about the nature of our mostcritical accounting estimates, our assumptions or approach used and the effectsof hypothetical changes in the material assumptions used to develop eachestimate.

 

*Nature of Critical EstimateItem:*Oil and Natural Gas Reserves -Our estimate of proved reserves is based on the quantities of oil and gas whichgeological and engineering data demonstrate, with reasonable certainty, to berecoverable in future years from known reservoirs under existing economic andoperating conditions. The accuracy of any reserve estimate is a function of thequality of available data, engineering and geological interpretation, andjudgment. For example, we must estimate the amount and timing of futureoperating costs, severance taxes, development costs, and workover costs, all ofwhich may in fact vary considerably from actual results. In addition, asprices and cost levels change from year to year, the economics of producing thereserves may change and therefore the estimate of proved reserves also may change.Any significant variance in these assumptions could materially affect theestimated quantity and value of our reserves. Despite the inherent imprecisionin these engineering estimates, our reserves are used throughout our financialstatements.

 

*Assumptions/ApproachUsed:*Units-of-productionmethod to amortize our oil and natural gas properties - The quantity of reserves couldsignificantly impact our depletion expense. Any reduction in proved reserveswithout a corresponding reduction in capitalized costs will increase thedepletion rate.

 

* *“Ceiling” Test — Thefull-cost method of accounting for oil and gas properties requires a quarterlycalculation of a limitation on capitalized costs, often referred to as afull-cost ceiling calculation. The ceiling is the discounted present value ofour estimated total proved reserves adjusted for taxes and the impact of hedgeson pricing, using a 10% discount rate. To the extent that our capitalized costs(net of accumulated depletion and deferred taxes) exceed the ceiling, theexcess must be written off to expense. Once incurred, this impairment of oiland gas properties is not reversible at a later date even if oil and gas pricesincrease. No such impairment was required in the years ended December 31,2005, 2004, and 2003. This calculation of our proved reserves couldsignificantly impact our ceiling limitation used in determining whether animpairment of our capitalized costs is necessary. The ceiling calculationdictates that prices and costs in effect as of the last day of the period aregenerally held constant indefinitely. Therefore, the future net revenuesassociated with the estimated proved reserves are not based on our assessmentof future prices or costs, but rather are based on prices and costs in effectas of the end of the period. Oil and natural gas prices used in the reservevaluation at December 31, 2005 were $61.04 per barrel and $10.05 perMMbtu. Commodity prices have decreased significantly since December 31,2005.

 

*Effect if differentassumptions used:*Units-of-productionmethod to amortize our oil and natural gas properties- A 10% increase or decrease in reserves would have decreased or increased,respectively, our depletion expense for the year by approximately 10%.

 

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“Ceiling”limitation test — The mostlikely factor 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, 2005, we had a cushion (i.e., the excess ofthe ceiling over our capitalized costs) of $151.1 million. A 10% increase ordecrease in prices used would have increased or decreased our cushion byapproximately 29%. Our hedging program would serve to mitigate some of theimpact of any price decline. Our hedges did not impact the ceiling test in the first,second or fourth quarter of 2005, but did reduce the ceiling in the thirdquarter by approximately $15.5 million. Our hedges would not have impacted theceiling if the natural gas price was 10% lower as these prices were within thecollars, but had we increased the natural gas price by 10% the natural gasprice would have been less than our hedge floor and therefore resulted in adecrease in the ceiling of $1.9 million. Another likely factor to contribute toa ceiling test impairment is a revised estimate of reserve volume. A 10%increase or decrease in reserve volume would have increased or decreased ourcushion by approximately 19%.

 

*Nature of Critical EstimateItem:*Unproved Property Impairment****- We haveelected to use the full-cost method to account for our oil and gas activities.Investments in unproved properties are not amortized until proved reservesassociated with the prospects can be determined or until impairment occurs. Unprovedproperties are evaluated quarterly for impairment on a property-by-propertybasis. If the results of an assessment indicate that an unproved property isimpaired, the amount of impairment is added to the proved oil and natural gasproperty costs to be amortized.

 

*Assumptions/Approach Used:*AtDecember 31, 2005, we had $36.9 million allocated to unproved property.This allocation is based on our estimation of whether the property haspotential attributable reserves. Therefore, our assessment of the potentialreserves will determine whether costs are moved from the unproved category tothe full-cost pool for depletion or whether an impairment is taken.

 

*Effect if differentassumptions used:* A 10% increaseor decrease in the unproved property balance (i.e., transfer to full-cost pool)would have increased or decreased our depletion expense by approximately 1% forthe year ended December 31, 2005.

 

*Nature of Critical EstimateItem:*Asset Retirement Obligations**-**We have certain obligations toremove tangible equipment and restore land at the end of oil and gas productionoperations. Our removal and restoration obligations are primarily associatedwith plugging and abandoning wells. Prior to January 1, 2003, the costsassociated with this activity were capitalized to the full-cost pool andcharged to income through depletion. We adopted Statement of FinancialAccounting Standards (“SFAS”) No. 143, *Accountingfor Asset Retirement Obligations* effective January 1, 2003, asdiscussed in Note 2 to our Consolidated Financial Statements. SFAS No. 143significantly changed the method of accruing for costs an entity is legallyobligated to incur related to the retirement of fixed assets (“asset retirementobligations” or “ARO”). Primarily, SFAS No. 143 requires us to estimateasset retirement costs for all of our assets, adjust those costs for inflationto the forecast abandonment date, discount that amount using acredit-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. When new obligations are incurred,i.e. new well drilled or acquired, we add a layer to the ARO liability. We thenaccrete the liability layers quarterly using the applicable period-endeffective credit-adjusted-risk-free rates for each layer. Should either theestimated life or the estimated abandonment costs of a property change upon ourquarterly review, a new calculation is performed using the same methodology oftaking the abandonment cost and inflating it forward to its abandonment dateand then discounting it back to the present using our credit-adjusted-risk-freerate. The carrying value of the asset retirement obligation is adjusted to thenewly calculated value, with a corresponding offsetting adjustment to the assetretirement cost (included in the full-cost pool); therefore, abandonment costswill almost always approximate the estimate. When well obligations are relievedby sale of the property or plugging and abandoning the well, the relatedliability and asset costs are removed from our balance sheet.

 

*Assumptions/ApproachUsed:*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 removal 

 

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technologies and costs are constantly changing, asare regulatory, political, environmental, safety and public relationsconsiderations. Inherent in the estimate of the present value calculation ofour AROs are numerous assumptions and judgments including the ultimatesettlement amounts, inflation factors, credit-adjusted-risk-free-rates, timingof settlement, and changes in the legal, regulatory, environmental andpolitical environments.

 

*Effect if differentassumptions used:* Since thereare so many variables in estimating AROs, we attempt to limit the impact ofmanagement’s judgment on certain of these variables by using input of qualifiedthird parties. We engage independent engineering firms to evaluate ourproperties annually. We use the remaining estimated useful life from theyear-end reserve reports by our independent reserve engineers in estimatingwhen abandonment could be expected for each property. We utilize a three-yearaverage rate for inflation to diminish any significant volatility that may bepresent in the short term. We expect to see our calculations impactedsignificantly if interest rates move from their current lows, as the credit-adjusted-risk-freerate is one of the variables used on a quarterly basis. We have developed astandard cost estimate based on historical costs, industry quotes and depth ofwells. Unless we expect a well’s plugging to be significantly different than anormal abandonment, we use this estimate. The resulting estimate, afterapplication of a discount factor and some significant calculations, coulddiffer from actual results, despite all our efforts to make an accurateestimate.

 

*Nature of Critical EstimateItem:*Income Taxes**-**In accordancewith the accounting for income taxes under SFAS No. 109, *Accounting for Income Taxes,* we haverecorded a deferred tax asset and liability to account for the expected futuretax 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 our ability to use all of our NOLcarryforwards that resulted from substantial income tax deductions, prior yearlosses and acquisitions. We consider future taxable income in making suchassessments. If we conclude that it is more likely than not that some portionor all of the deferred tax assets will not be realized under accountingstandards, it is reduced by a valuation allowance.

 

*Assumptions/ApproachUsed:*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). We are not currently required to payany federal income taxes because of the prior generation of NOL’s carryforwards.

 

*Effect ifdifferent assumptions used:* We have engaged an independent public accounting firm to assist us inapplying the numerous and complicated tax law requirements. However, despiteour attempt to make an accurate estimate, the ultimate utilization of our NOLcarryforwards is highly dependent upon our actual production and therealization of taxable income in future periods. If we estimate that some orall of our NOL carryforwards are more likely than not going to expire orotherwise not be utilized to reduce future tax, we would record a valuationallowance to remove the benefit of those NOL carryforwards from our financialstatements.

 

*Nature ofCritical Estimate Item:*Derivative and Hedging Activities**-**Dueto the instability of oil and natural gas prices, we may enter into, fromtime to time, price-risk management transactions (e.g., swaps, collars andfloors) 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 theyqualify for cash flow hedge accounting. In accordance with SFAS No. 133, *Accounting for Derivative Instruments and HedgingActivities (as amended),*all transactions are recorded on thebalance sheet at fair value. See*ITEMS 1 AND2. “BUSINESS AND PROPERTIES**–*MARKETING.”

 

HedgeContracts - We formally assess, both at the hedge’s inception and on an ongoingbasis, whether the derivatives that are used for hedging are expected to behighly effective in offsetting changes in cash flows of the hedged transactions.In the event it is determined that the use of a particular derivative may notbe 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 

 

39

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incomestatement. The effective portion of the changes in the fair value of hedgecontracts is recorded initially in OCI. When the hedged production is sold, therealized gains and losses on the hedge contracts are removed from OCI andrecorded in revenue. Ineffective portions of the changes in the fair value ofthe hedge contracts are recognized in revenue as they occur. While the hedgecontract is outstanding, the ineffective gain or loss may increase ordecrease until settlement of the contract.

 

DerivativeContracts - For transactions not accounted for using cash flow hedgeaccounting, the change in the fair value of the derivative contract isreflected in revenue immediately, and not deferred through OCI, and there is nomeasurement of effectiveness.

 

*Assumptions/Approach Used:*Estimatingthe fair values of derivative instruments requires complex calculations,including the use of a discounted cash flow technique, estimates of risk andvolatility, and subjective judgment in selecting an appropriate discount rate.In addition, the calculations use future market commodity prices, whichalthough posted for trading purposes, are merely the market consensus of forecastedprice trends. The results of the fair value calculations cannot be expected torepresent exactly the fair value of our commodity hedges. We currently obtainthe fair value of our positions from our counterparties. Our practice ofrelying on our counterparties who are more specialized and knowledgeable inpreparing these complex calculations reduces our management’s input.

 

*Effect ifdifferent assumptions used:* At December 31, 2005, a 10% change in the commodity price perunit, as long as the price is either above the ceiling or below the floorprice, would cause the fair value total of our derivative financial instrumentto increase or decrease by approximately $0.3 million.

 

# **RESULTSOF OPERATIONS**

 

This section includesdiscussion of our 2005, 2004 and 2003 results of operations. We are anindependent energy company engaged in the exploration, development, acquisitionand production of oil and natural gas. Our resources and assets are managed andour results reported as one operating segment. We conduct our operationsprimarily along the onshore United States, Gulf Coast, with our primaryemphasis in south Texas, Mississippi, Louisiana and southeastern New Mexico.

 

**Revenue and Production**

 

Our primary source of production and revenue isnatural gas. For the years ended December 31, 2005, 2004 and 2003, ourproduct mix contributed the following percentages of production and revenues:

 
| ** **          | ** ** | **REVENUES (1)** | ** ** |
|---------------------|------------|-----------------------|------------|
| ** **          | ** ** | **2005**              | ** ** | **2004** | ** ** | **2003** | ** ** |
| Natural gas         |       | 82                    | %          | 82 | % | 82 | % |
| Natural gas liquids |       | 5                     | %          | 7 | % | 7 | % |
| Crude oil           |       | 13                    | %          | 11 | % | 11 | % |
|                |       |                  |       |   |   |   |   |
| Total               |       | 100                   | %          | 100 | % | 100 | % |

 

----

(1)          Includeseffect of hedging and derivative transactions.

 
| ** **          | ** ** | **PRODUCTION VOLUMES (MCFE)** | ** ** |
|---------------------|------------|-----------------------------------------|------------|
| ** **          | ** ** | **2005**                                | ** ** | **2004** | ** ** | **2003** | ** ** |
| Natural gas         |       | 77                                      | %          | 75 | % | 78 | % |
| Natural gas liquids |       | 11                                      | %          | 14 | % | 13 | % |
| Crude oil           |       | 12                                      | %          | 11 | % | 9 | % |
|                |       |                                    |       |   |   |   |   |
| Total               |       | 100                                     | %          | 100 | % | 100 | % |

 

Our revenue is sensitive to changes in prices received for our products. Asubstantial portion of our production is sold at prevailing market prices,which fluctuate in response to many factors that are outside of our control. Imbalancesin the supply and demand for oil and natural gas can have a dramatic effect onthe prices we receive for our production. Political instability andavailability of alternative fuels could impact worldwide supply, 

 

40

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while, the economy, weather and other factors outside of our controlcould impact demand. Duringthe third quarter of 2005, two large hurricanes impacted the Gulf Coast area, causingsignificant damage to platforms in the Gulf and numerous onshore facilitiesrelated to our industry. As a result, both oil and natural gas pricesincreased. We were fortunate to only experience minor production deferrals as aresult of these hurricanes. We completed two acquisitions in the fourth quarterof 2005, which did not have significant impact on revenues and production dueto timing, but we expect them to be a source of growth in 2006.

 

The followingtable summarizes production volumes, average sales prices and operating revenuefor our oil and natural gas operations for the years ended December 31, 2005,2004 and 2003.

 
| ** **                              | ** ** | ** **            | ** **  | **% Increase  (Decrease)** | ** ** |
|-----------------------------------------|------------|-----------------------|-------------|---------------------------------|------------|
| ** **                              | ** ** | **December 31,** | ** **  | **05 vs.**                 | ** ** | **04 vs.** | ** ** |
| ** **                              | ** ** | **2005**              | ** **  | **2004**                        | ** ** | **2003** | ** ** | **04** | ** ** | **03** | ** ** |
| **Production  Volumes:**                |       |                  |        |                            |       |   |   |   |   |   |   |
| Natural gas  (Mcf)                      |       | 12,596,503            |        | 9,148,191                       |       | 6,290,055 |   | 38 | % | 45 | % |
| Natural gas  liquids (Bbls)             |       | 307,596               |        | 276,184                         |       | 177,892 |   | 11 | % | 55 | % |
| Oil and  condensate (Bbls)              |       | 323,640               |        | 214,622                         |       | 122,592 |   | 51 | % | 75 | % |
| Natural gas  equivalent (Mcfe)          |       | 16,383,916            |        | 12,093,027                      |       | 8,092,961 |   | 35 | % | 49 | % |
| **Average  Sales Price:**               |       |                  |        |                            |       |   |   |   |   |   |   |
| Natural gas  ($per Mcf)(1)              |       | $                     | 7.97        |                            | $          | 5.91 |   | $ | 5.14 |   | 35 | % | 15 | % |
| Natural gas  liquids ($per Bbl)         |       | 18.45                 |        | 15.83                           |       | 12.37 |   | 17 | % | 28 | % |
| Oil and  condensate ($per Bbl)(1)       |       | 53.57                 |        | 39.77                           |       | 31.48 |   | 35 | % | 26 | % |
| Natural gas  equivalent ($per Mcfe) (2) |       | 7.40                  |        | 5.33                            |       | 4.19 |   | 39 | % | 27 | % |
| **Operating  Revenue:**                 |       |                  |        |                            |       |   |   |   |   |   |   |
| Natural gas  (1)                        |       | $                     | 100,437,147 |                            | $          | 54,056,944 |   | $ | 32,322,043 |   | 86 | % | 67 | % |
| Natural gas  liquids                    |       | 5,676,603             |        | 4,373,245                       |       | 2,200,350 |   | 30 | % | 99 | % |
| Oil and  condensate(1)                  |       | 17,336,592            |        | 8,535,222                       |       | 3,859,204 |   | 103 | % | 121 | % |
| Loss on  hedging and derivatives        |       | (2,267,253            | )           | (2,460,063                      | )          | (4,455,590 | ) | 8 | % | 45 | % |
| Total (2)                               |       | $                     | 121,183,089 |                            | $          | 64,505,348 |   | $ | 33,926,007 |   | 88 | % | 90 | % |

 

----

(1) Excludesthe effect of hedging and derivative transactions.

(2) Includesthe effect of hedging and derivative transactions.

 

Natural gas revenue, excluding hedgingactivity, increased 86% for the year ended December 31, 2005 over the sameperiod in 2004 and 67% for the year ended December 31, 2004 over the sameperiod in 2003. This growth trend is due to significantly higher production andhigher realized prices. Average natural gas production increased from 17.2 MMcf/din 2003 to 25.0 MMcf/d in 2004 and to 34.5 MMcf/d in 2005. Production increasesin 2004 and 2005 as compared to 2003 have been the result of significantdrilling at our Gato Creek and Encinitas properties in 2004 and Queen City andsoutheast New Mexico in 2005. In addition, a significant amount of growth hascome from acquisitions, including the Miller and the south Texas properties inlate 2003, the Contango properties (on Queen City) in late 2004 and ChapmanRanch Field in late 2005, for which the impact will be more noticeable in 2006.Partially offsetting the increases in production were natural declines at our O’ConnorRanch and O’Connor Ranch East properties in 2004 as compared to 2003, and naturaldeclines at O’Connor Ranch East and Brandon and increasing salt water productionat Duson Horst in 2005 as compared to 2004. Excluding the effect of hedges, theaverage natural gas sales price for production in 2005 was $7.97 per Mcfcompared to $5.91 per Mcf for 2004. This increase in average price receivedresulted in increased revenue of approximately $26.0 million (based on 2005year production). The overall increase in production in 2005 compared to 2004resulted in an increase in revenue of approximately $20.4 million (based on2004 comparable period pre-hedge prices). The overall increase in production in2004 compared to 2003 resulted in an increase in revenue of approximately $14.7million (based on 2003 comparable period pre-hedge prices). Excluding theeffect of hedges, the average natural gas sales price for production in 2004was $5.91 per Mcf compared to $5.14 per Mcf for 2003. This increase in averageprice received resulted in increased revenue of approximately $7.0 million(based on 2004 year production).

 

Revenue from the sale of NGLs increased 30%for the year ended December 31, 2005 over the same period in 2004 and 99%for the year ended December 31, 2004 over the same period in 2003. Daily productionvolumes for 

 

41

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NGLs increased from 487 Bbls/d for the year ended December 31, 2003to 755 Bbls/d for 2004 and to 843 Bbls/d in 2005, due primarily to increasedproduction from new 2004 wells drilled at Gato Creek, Encinitas, Santellana,and southeast New Mexico, those acquired at year-end 2003 from Miller and insouth Texas, and new processing and treating agreements entered into during2004. Partially offsetting production increases were declines at our Brandon,Duson Horst and States properties. Our production at Gato Creek receives alower average price on NGL’s (approximately $1.20 per barrel) due to the termsof our marketing agreement for that area. In 2003, the majority of our NGLproduction came from Gato Creek, whereas in 2004 and 2005 we have added moremarket priced production that has increased our overall price realized. Theaverage realized price for NGLs for the year ended December 31, 2005 was$18.45 per barrel as compared to $15.83 per barrel in 2004 and $12.37 perbarrel for the same period in 2003. The increase in NGL production in 2005increased revenue by approximately $0.5 million (based on 2004 comparableperiod average prices). Higher average realized prices for the year ended December 31,2005 resulted in an increase in revenue of approximately $0.8 million (based on2005 production). The increase in NGL production in 2004 increased revenue byapproximately $1.2 million (based on 2003 comparable period average prices). Higheraverage realized prices for the year ended December 31, 2004 resulted inan increase in revenue of approximately $1.0 million (based on 2004production).

 

Revenue from the sale of oil and condensate,excluding derivative activity, increased 103% for the year ended December 31,2005 over the same period in 2004 and 121% for the year ended December 31,2004 as compared to the same period in 2003 due to increased realized pricesand production. The average realized price for oil and condensate before thederivative losses for the year ended December 31, 2005 was $53.57 perbarrel compared to $39.77 per barrel in the same period of 2004. These higheraverage prices for 2005 resulted in an increase in revenue of approximately$4.5 million (based on 2005 production). The average realized price for oil andcondensate before the derivative losses for the year ended December 31,2004 was $39.77 per barrel compared to $31.48 per barrel in the same period of2003. These higher average prices for 2004 resulted in an increase in revenueof approximately $1.8 million (based on 2004 production). Production volumesfor oil and condensate increased to 887 Bbls/d for the year ended December 31,2005 from 586 Bbls/d for the same period in 2004 and 336 Bbls/d for the sameperiod in 2003. The increase in 2005 as compared to 2004 was due primarily to successfuldrilling in southeast New Mexico and at our Queen City and Encinitas projects,as well as the acquisition of existing production in the Queen City trend on December 29,2004, partially offset by declines at the Duson Horst and Brandon projects. Theincrease in 2005 oil and condensate production as compared to 2004 resulted inan increase in revenue of approximately $4.3 million (based on 2004 comparableperiod average prices). The increase in 2004 as compared to 2003 was 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 2004 oil and condensateproduction as compared to 2003 resulted in an increase in revenue ofapproximately $2.9 million (based on 2003 comparable period average prices).

 

Losses on hedging and derivatives have declinedsignificantly since 2003. This has been a function of the types of contractsand the strategy applied in our price risk-management activities. The volumeand price contract terms vary from period to period and therefore interactdifferently with the market prices. While we are unable to predict the marketprices, we enter into contracts that we expect will protect us in the event ofsignificant downturns in the market. In 2003, the losses were attributable 100%to natural gas contracts as compared to 2004 and 2005 when we began hedging ouroil production. The following table summarizes the various components of thetotal loss on hedging and derivatives for each of the three years ended December 31,2005, 2004 and 2003 and the impact each component had on our realized prices:

 

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| ** **                                                                       | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                       | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                                       | ** ** | **$**                                      | ** ** | **$ per unit** | ** ** | **$** | ** ** | **$ per unit** | ** ** | **$** | ** ** | **$ per unit** | ** ** |
| ** **                                                                       | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Natural gas  hedging contract settlements (Mcf)                                  |       | $                                          | (1,229,900 | ) | $ | (0.10 | ) | $ | (328,500 | ) | $ | (0.04 | ) | $ | (4,455,590 | ) | $ | (0.71 | ) |
|                                                                             |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Crude oil  derivative contract settlements (Bbl)                                 |       | (1,757,766                                 | )          | (5.43 | ) | (880,765 | ) | (4.10 | ) | — |   | — |   |
|                                                                             |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Hedge  premium reclassification (Mcf)                                            |       | —                                     |       | — |   | (686,250 | ) | (0.08 | ) | — |   | — |   |
|                                                                             |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Mark-to-market  reversal of prior period unrealized change in fair value (Bbl)   |       | 564,548                                    |       | 1.74 |   | — |   | — |   | — |   | — |   |
|                                                                             |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Mark-to-market  unrealized change in fair value of oil derivative contract (Bbl) |       | 155,865                                    |       | 0.48 |   | (564,548 | ) | (2.63 | ) | — |   | — |   |
|                                                                             |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Loss on  hedging and derivatives (Mcfe)                                          |       | $                                          | (2,267,253 | ) | $ | (0.14 | ) | $ | (2,460,063 | ) | $ | (0.20 | ) | $ | (4,455,590 | ) | $ | (0.55 | ) |

 

Should crude oil or natural gas prices increase or decreasefrom the current levels, it could materially impact our revenues. In a high-priceenvironment, hedged positions could result in lost opportunities if there is aceiling in place, thus lowering our effective realized prices on hedgedproduction, but in an environment of falling prices these transactions offersome pricing protection for hedged production. Our physical sales of thesecommodities are vulnerable to the volatility of the market price movements,therefore we typically enter into contracts covering a portion of anticipatedproduction to ensure certain cash flows that allow us to plan our businessactivities.

 

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**Costs and Operating Expenses**

 

The table below presents a detail of the years endedDecember 31, 2005, 2004 and 2003 expenses:

 
| ** **                                            | ** ** | ** **            | ** ** | **% Increase (Decrease)** | ** ** |
|-------------------------------------------------------|------------|-----------------------|------------|--------------------------------|------------|
| ** **                                            | ** ** | **December 31,** | ** ** | **05 vs.**                | ** ** | **04 vs.** | ** ** |
| ** **                                            | ** ** | **2005**              | ** ** | **2004**                       | ** ** | **2003** | ** ** | **04** | ** ** | **03** | ** ** |
| ** **                                            |       |                  |       |                           |       |   |   |   |   |   |   |
| Oil and natural gas operating expenses                |       | $                     | 8,478,525  |                           | $          | 4,945,918 |   | $ | 2,676,050 |   | 71 | % | 85 | % |
| Severance and ad valorem taxes                        |       | 8,589,484             |       | 4,362,852                      |       | 2,439,744 |   | 97 | % | 79 | % |
| Depreciation,  depletion, amortization and accretion: |       |                  |       |                           |       |   |   |   |   |   |   |
| Oil and gas  property and equipment                   |       | 39,810,257            |       | 21,471,606                     |       | 12,906,956 |   | 85 | % | 66 | % |
| Other assets                                          |       | 266,737               |       | 357,300                        |       | 603,698 |   | (25 | )% | (41 | )% |
| ARO  accretion                                        |       | 141,120               |       | 98,968                         |       | 66,625 |   | 43 | % | 49 | % |
| General and administrative:                           |       |                  |       |                           |       |   |   |   |   |   |   |
| Deferred  compensation – repriced options        |       | 1,627,814             |       | 1,135,628                      |       | 1,219,349 |   | 43 | % | (7 | )% |
| Deferred  compensation – restricted stock        |       | 973,796               |       | 498,372                        |       | 372,151 |   | 95 | % | 34 | % |
| Bad debt  expense                                     |       | 65,157                |       | —                         |       | — |   |   | * |   | * |
| Other  general and administrative                     |       | 9,769,281             |       | 7,812,970                      |       | 5,540,140 |   | 25 | % | 41 | % |
| Total operating expenses                              |       | 69,722,171            |       | 40,683,614                     |       | 25,824,713 |   | 71 | % | 58 | % |
| Other expense, net                                    |       | 24,730                |       | 437,459                        |       | 662,287 |   | (94 | )% | (34 | )% |
| Total expense                                         |       | $                     | 69,746,901 |                           | $          | 41,121,073 |   | $ | 26,487,000 |   | 70 | % | 55 | % |

 

----

*Not meaningful

 

Oil and natural gas operating expenses increased 85%between 2003 and 2004 and 71% between 2005 and 2004, a 217% increase of 2005over 2003. The increase from 2003 to 2005 has been driven almost equally byactivity increases and cost increases. Activity levels were impacted bybringing online 40 apparently successful wells during 2004 and 62 apparently successfulwells in 2005. The 2005 and 2004 results were impacted by the addition of theMiller and south Texas properties (acquisitions late in 2003) that accountedfor 26% of the total costs in 2004 and 23% in 2005. The 2005 results had theadded costs from the newly acquired Contango properties (late 2004), whichaccount for 21% of total costs in 2005, representing 50% of the increase from2004 to 2005 and 31% of the increase from 2003 to 2005. The acquisitions of theChapman Ranch Field properties late in 2005 should also add to costs in 2006. Operatingexpenses averaged $0.52 per Mcfe, $0.41 per Mcfe and $0.33 per Mcfe for theyears ended December 31, 2005, 2004 and 2003, respectively. The increasingcost structure resulted from added costs for compression, workovers andsalt-water disposal as well as inflation in our industry during 2005. We arewitnessing increasing costsdue to increased demand for oil field products and services. The oil andnatural gas industry tends to be cyclical in nature and the demand for goodsand services of oil field companies, suppliers and others associated with theindustry can put extreme pressure on the economic stability and pricingstructure within the industry. Typically, as prices for oil and natural gasincrease, so do many or all associated costs. When commodity prices decline,associated costs do not necessarily decline at the same rate.

 

Severance and ad valorem taxes increased in bothperiods. Severance tax expense for 2005 was 76% higher than 2004 and 2004 was 97%higher than 2003. Severance taxes are levied directly on our revenue dollars,so the increase is consistent with the increases in revenue. The severance taxrate realized increased from 5.3% in 2003 to 6.0% in 2004 and then decreased to5.7% in 2005. The rate realized changes as a result of the changing mix of ourproduction locations. We had a significant portion of production in otherstates such as Louisiana in 2003 as compared to the increase in production inTexas in 2004, which imposes a tax rate of approximately 7.5% of the revenuedollar. In 2005, we had an increasing amount of production in New Mexico whichadded another location to the mix. Ad valorem costs increased 296% in 2005 ascompared to 2004 but decreased 5% in comparing 2004 to 2003. Increasedcommodity prices in 2005 resulted in a higher valuation of reserves by taxingauthorities resulting 

 

44

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inhigher ad valorem taxes on certain properties. The property additions in 2003were not as significant as those we acquired on December 29, 2004, which representeda significant portion of the total cost in 2005. We also realized approximately$0.6 million of 2004 expense in 2005 due to very late timing of unexpected costs,which represents 35% of the total 2005 cost. On an equivalent basis, severanceand ad valorem taxes averaged $0.52 per Mcfe, $0.36 per Mcfe and $0.30 per Mcfefor the years ended December 31, 2005, 2004 and 2003, respectively.

 

Depletion, depreciation and amortization (“DD&A”)and accretion expense for the year ended December 31, 2005 increased 83%over the year ended December 31, 2004 and 62% for the year ended December 31,2004 over the year ended December 31, 2003. Full cost depletion on our oiland natural gas properties totaled $39.8 million in 2005, $21.5 million in 2004and $12.9 million in 2003. These increases were driven by production volumeincreases in 2004 and depletion rate increases in 2005. For the year ended December 31,2005, higher oil and natural gas production compared to the prior year periodresulted in an increase in depletion expense of $7.6 million. Depletion expenseon a unit of production basis for the year ended December 31, 2005 was $2.43per Mcfe, 37% higher than the 2004 rate of $1.78 per Mcfe. The higher depletionrate per Mcfe resulted in an increase in depletion expense of $10.7 million. Theincrease in the depletion rate was primarily due to a higher amortizable basein 2005 compared to the prior year without a corresponding increase in reserves.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 productionbasis for the year ended December 31, 2004 was $1.78 per Mcfe, 12% higherthan the 2003 rate of $1.59 per Mcfe. The higher depletion rate per Mcferesulted in an increase in depletion expense of $2.2 million. The increase inthe depletion rate was primarily due to a higher amortizable base in 2004compared to the prior year without a corresponding increase in reserves. Depreciationof other assets decreased 25% from 2004 to 2005 and 41% from 2003 to 2004 dueto accelerating depreciation on leasehold improvements and computer equipmentin 2003 and 2004. When we moved to a new office building early in 2003, wefully depreciated certain assets that would no longer be in service in the newlocation. Many older assets became fully depreciated at that time and were notreplaced in 2004 and 2005. Accretion expense on our ARO liability has increased 43% in 2005and 49% in 2004 for the addition of new obligations associated with wells addedeach year, as well as the fact that accretion is calculated using the interestmethod of allocation, which calculates interest on the cumulative balance suchthat the interest increases with each subsequent period.

 

Total general and administrative (“G&A”)expenses for the year ended December 31, 2005 were $12.4 million, anincrease of 32% compared to the 2004 total of $9.4 million and 74% compared tothe 2003 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 compensation expense consists of costsreported in accordance with FIN 44**and amortization related to restricted stockawards. FIN 44 requires variable accounting for stock options with termsmodified after issuance (see Note 2 to our consolidated financial statements).Variable accounting provides for a non-cash charge to compensationexpense if the price of our common stock on the last trading day of a reportingperiod is greater than the exercise price of certain re-priced options. FIN 44could also result in a credit to compensation expense to the extent that thetrading price declines from the trading price as of the end of the priorperiod, but not below the exercise price of the options. We adjust deferredcompensation expense upward or downward on a monthly basis based on the tradingprice at the end of each such period. We are required to report under this rule asa result of non-qualified stock options granted to employees and directors inprior years and re-priced in May of 1999, as well as certain newly issuedoptions in conjunction with the re-pricing. A FIN 44 charge on our re-priced stock options was required in 2005, 2004and 2003 as a result of our stock price exceeding the exercise price of thosere-priced options. The average price at December 31, 2005, 2004 and 2003that was used to calculate this expense was $24.65 per share, $14.66 per shareand $10.60 per share, respectively. The increase in deferredcompensation for restricted stock awards is related to the increase in employeeheadcount during 2004 and 2005.

 

Other G&A expenses, which does not include thedeferred compensation expenses discussed above, increased 25% over 2004 whichwas 41% higher than 2003. The increase in other G&A from 2003 to 2005 wasin part attributable to the growth in our company from 35 full-time andtwo part-time employees at December 31, 2003 to 62 full-time employees at December 31,2005. In 2004 and 2005, we added new corporate office space to house the growthin our Company, which increased our rent expense. We also have been impacted byhigher audit and legal fees and amounts spent on investor relations projects during2004 and 2005. We incurred approximately $390,400 of costs for theimplementation of the Sarbanes-Oxley 404 Internal Control Report during 2004,but none in 2003. In 2005, we realized additional costs related to the 2004 InternalControl report of approximately $92,700 that were unexpected. In 2005, thetotal estimated costs related to the 2005 Internal Control report areapproximately $345,100. This does not include any amounts of the significantinternal resources that were directed towards this 

 

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project,especially the internal audit department we added during 2005. These increaseswere partially offset by decreases in general office related spending in 2004. Includedin 2005 were charitable contributions of $100,000 to the Hurricane Katrinarelief effort and bad debt expense of $65,157 for joint interest owner accountsreceivable that we believe are uncollectible. Included in 2003 was a $70,000settlement for a lawsuit related to seismic rights. For the years ended December 31,2005, 2004 and 2003, overhead reimbursement fees reduced G&A costs byapproximately $287,900, $262,000 and $120,500, respectively. We capitalized $2.6million, $2.2 million and $1.7 million of general and administrative costs in 2005,2004 and 2003, respectively. Overall other G&A is increasing as the Companygrows, but we are maintaining discipline in controlling our costs and realizinggreater benefits from the growth, such as increased production volumes andrevenues. Other G&A expenses on a unit of production basis for the yearsended December 31, 2005, 2004 and 2003 were $0.60 per Mcfe, $0.65 per Mcfeand $0.68 per Mcfe, respectively. We believe that the downward trend in this perunit cost structure is indicative of our attention to controlling costs.

 

Other income (expense) excludes interestexpense for the year ended December 31, 2005 because 100% of our interestexpense was capitalized as compared to the years ended December 31, 2004and 2003 in which only a portion was capitalized. We incurred higherinterest costs for the year ended December 31, 2005 than for the sameperiod of 2004 and 2003 due to higher commitment fees and higher interestrates, but we capitalized all of our expense as a result of our unproved propertybalance exceeding our weighted average debt balance. At December 31, 2005,2004 and 2003 our unprovedproperty balance was $36.9 million, $15.5 million and $5.0 million,respectively.

 
| ** **                 | ** ** | **For the Year Ended December 31,** | ** ** |
|----------------------------|------------|------------------------------------------|------------|
| ** **                 | ** ** | **2005**                                 | ** ** | **2004** | ** ** | **2003** | ** ** |
|                       |       |                                     |       |   |   |   |   |
| Gross interest             |       | $                                        | 1,943,335  |   | $ | 1,033,053 |   | $ | 923,308 |   |
| Less: Capitalized interest |       | (1,943,335                               | )          | (701,654 | ) | (244,503 | ) |
| Interest expense, net      |       | $                                        | —     |   | $ | 331,399 |   | $ | 678,805 |   |
|                       |       |                                     |       |   |   |   |   |
| Weighted Average Debt      |       | $                                        | 24,189,041 |   | $ | 20,027,322 |   | $ | 22,993,425 |   |

 

Also included in other income (expense) for the yearended December 31, 2005 and 2004 was $152,723 and $142,135 representingamortization of deferred loan costs associated with our credit facility. Therewere no such costs in 2003.

 

Also included in other income (expense) was interestincome, which totaled $127,993, $36,075, and $16,518 for the years ended December 31,2005, 2004 and 2003, respectively. The interest is earned on daily cash investedin overnight money market funds. We have had increased cash on hand in recentyears providing for the increased interest income.

 

We are subject to state andfederal income taxes and although we are currently generating taxable incomefor financial reporting purposes, we are not in a federal income tax paying positionas a result of deducting intangible drilling costs (“IDC”) that reduce ourtaxable income for income tax purposes and NOL carryforwards that offset anyremaining taxable income. Deferred income tax provisions of $18.1 million, $8.3million and $ 2.7 million were recorded for the years ended December 31,2005, 2004 and 2003, respectively. The majority of the increase year over yearhas been the growth in income before income taxes. Due to changes in amounts ofpermanent tax differences, including meals and entertainment and compensationexpense, our effective tax rate also changes from time to time. The effectiverate was 35.2% for the year ended December 31, 2005, as compared to 35.3%in 2004 and 36.7% in 2003. As of December 31, 2005, approximately $55.8million of net operating loss carryforwards have been accumulated or acquiredthat will begin to expire in 2020. We were required to make an alternativeminimum tax payment for 2005 of $327,400.

 

Upon adoption of SFAS No. 143 on January 1,2003, we recorded a cumulative effect of a change in accounting principal of$357,825 (net of income taxes of $192,675) and accretion expense, to recognizetransition amounts for asset retirement obligations, asset retirement costs andaccumulated depletion and accretion.

 

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For the year ended December 31, 2005, we hadnet income of $33.4 million, or $1.95 per basic and $1.87 per diluted earningsper share, as compared to $15.1 million, or $1.16 basic earnings per share and$1.11 diluted earnings per share in the same period of 2004 and net income aftercumulative effect of a change in accounting principle of $4.4 million, or $0.45basic and $0.44 diluted earnings per share in 2003. Basic weighted averageshares outstanding increased from approximately 9.7 million at December 31,2003 to 13.0 million at December 31, 2004 and to 17.1 million at December 31,2005. The impact of the shares issued in the Miller transaction was not fullyrealized until 2004 since the merger closed and the shares were issued in December 2003.The same was true in 2004 for the shares issued in the public offering in December 2004.There were also minimal increases due to options exercised and vesting ofrestricted stock during 2004 and 2005.

 

**LIQUIDITY AND CAPITAL RESOURCES**

 

Our primary ongoing source of capital is the cashflow generated from our operating activities supplemented by borrowings underour credit facility. Net cash generated from operating activities is a functionof production volumes and commodity prices, both of which are inherentlyvolatile and unpredictable, as well as operating efficiency and capitalspending. Our business, as with other extractive businesses, is a depleting onein which each gas equivalent unit produced must be replaced or our asset baseand capacity to generate revenues in the future will shrink. Our overall expectedfuture production decline is estimated to be approximately 22% per year. Lesspredictable than production declines from our proved reserves is the impact ofconstantly changing oil and natural gas prices on cash flows and, thereforecapital budgets. We attempt to mitigate the price risk with our hedgingprogram. Reserves and production volumes are influenced, in part, by the amountof future capital expenditures. In turn, capital expenditures are influenced bymany factors including drilling results, oil and gas prices, industryconditions, prices, availability of goods and services and the extent to whichoil and gas properties are acquired.

 

Our primary cash requirements are for exploration,development and acquisition of oil and gas properties, and the repayment ofprincipal and interest on outstanding debt. We attempt to fund our explorationand development activities primarily through internally generated cash flowsand budget capital expenditures based on projected cash flows. We routinelyadjust capital expenditures in response to changes in oil and natural gasprices, drilling and acquisition costs, and cash flow. We have historicallyused our credit facility to supplement any deficiencies between operating cashflow and capital expenditures. We typically have funded acquisitions fromborrowings under our credit facility, cash flow from operations and sales ofcommon stock.

 

Significant changes to working capital may affectour liquidity in the short term. The increase in accrued fees for professionalservices and royalties payable at December 31, 2005 accounts for most ofthe increase in accrued liabilities. Therefore, we expect our short-term cashoutflows for the first quarter of 2006 to increase as these liabilities comedue. There are also advance payments made to one of our operators included in ourcurrent assets. As the actual costs are realized, this balance will diminish. Theincrease in the derivative instrument liability is indicative of potentialfuture cash settlements on our hedge positions, which are scheduled to settlein the coming months. The fair market value of our outstanding hedge andderivative contracts is reflected on the balance sheet as a liability for thepositions with each of our two counterparties. This hedge and derivativefinancial instrument is a liability because the future strip commodity pricesexceed the price caps on our contracts at the balance sheet date, such that ifthe contracts were to settle at the balance sheet date we would havesignificant losses. The fair market value represents the potential settlementfor those contracts if the market prices remain unchanged, but should commodityprices increase or decrease, the fair value of those outstanding contractswould change and the settlements at maturity would also change. When our hedgesand derivatives require us to pay a cash settlement, we are receiving highercash inflows on the sale of unhedged production at higher prices, providing uswith funds which would adequately cover any derivative and hedge payments whenthey come due.

 

We have historically used our credit facilityto supplement any deficiencies between operating cash flow and capital expenditures.We had $85.0 million outstanding under the credit facility at December 31,2005. The maturity for this credit facility is December 31, 2007.

 

After considering the impact of these workingcapital changes and our forecasts of future results of operations, we believethat cash flows from operating activities, as supplemented by borrowings on ourcredit facility, combined with our ability to control the timing of certain ofour future exploration and development requirements, will provide us with theflexibility and liquidity to meet our planned capital requirements for 2006. In

 

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addition, our credit facility had $25.0 million available at December 31,2005 for general corporate purposes, exploratory and developmental drilling andacquisitions of oil and gas properties.

 

During 2004 and early 2005, we realizedincreased cash flows as a result of our public stock offerings and exercises ofoptions and warrants to acquire shares of our common stock. Most significantwere the net proceeds of $47.8 million that we received, before direct costs of$0.6 million, from our December 2004 offering of our common stock and therelated exercise of the underwriter’s over-allotment option for 525,000additional shares of our common stock, resulting in an additional $7.2 millionof net proceeds to us in January 2005. At December 31, 2005, we hadcertain options outstanding and exercisable for shares of our common stock. Wetypically do not rely on proceeds from the exercise of warrants and stockoptions to sustain our business as the timing of their exercise isunpredictable.

 

We had cash and cash equivalents at December 31,2005 of $0.7 million consisting primarily of short-term money marketinvestments, as compared to $2.3 million at December 31, 2004. Workingcapital was $10.5 million as of December 31, 2005, as compared to $9.0million at December 31, 2004.

 

*Net Cash Provided By Operating Activities*

 

Cash flows provided by operating activities were $93.1million, $42.3 million and $23.9 million for the years ended December 31,2005, 2004, and 2003, respectively. The significant increase in cash flowsprovided by operating activities for the year ended December 31, 2005compared to 2004 and 2003 was primarily due to higher oil and gas productionrevenue partially offset by higher operating expense.

 

Net cash generated from operating activities is afunction of commodity prices, which are inherently volatile and unpredictable,production and capital spending. In an effort to reduce the volatility realizedon commodity prices, we enter into derivative instruments. Due to inflatedcrude oil market pricing, the impact related to the derivatives for 2005 hasbeen negative, as the prices have exceeded the highs we originally expected. Wehave realized the benefit of these high prices on our crude oil production, butalso realized the negative impact from cash settlements of $1.8 million on ourcrude oil derivatives. We have also paid $1.2 million of net cash settlementson our natural gas hedges due to the natural gas market prices rising above ourhedge ceilings. Overall, oil and gas production revenue for 2005 increased 88%over 2004 and 257% over 2003.

 

Although fluctuations in commodity prices have beenthe primary reason for our short-term changes in cash flow from operatingactivities, increased production volumes significantly impacted us in 2005. Ourbusiness, as with other extractive businesses, is a depleting one in which eachgas equivalent produced must be replaced or our asset base and capacity togenerate revenues in the future will shrink. Our ability to prevent shrinkagewill be affected in the future by the successes and/or failures of ourexploration, production and acquisition activities. Less predictable thanproduction declines from our proved reserves is the impact of constantlychanging oil and natural gas prices on cash flows and, therefore capitalbudgets.

 

For these reasons, we only forecast, for internaluse by management, an annual cash flow. We do analyze contingent wellopportunities that may extend further than one year, but do not rely onthem for sustaining our business. These annual forecasts are revised monthlyand capital budgets are reviewed by management and adjusted as warranted bymarket conditions. Longer-term cash flow and capital spending projections areneither developed nor used by management to operate our business.

 

In the event such capital resources are notavailable to us, our drilling and other activities may be curtailed. See *ITEMS 1A. “RISK FACTORS* – Our operations have significant capitalrequirements which, if not met will hinder operations.”

 

*Net Cash Used In Investing Activities*

 

***We reinvest a substantial portionof our cash flows in our drilling, acquisition, land and geophysical activities.As a result, we used $167.3 million in investing activities during 2005.Capital expenditures of $79.1 million were attributable to the drilling of 65 grosswells, 62 of which were apparently successful. Acquisition costs related to theprivate company corporate acquisition totaled $39.0 million, net of cashacquired, and other acquisition costs totaled $28.0 million, mainly related tothe Chapman Ranch Field asset acquisition. Other spending includes $14.4million in expenditures attributable to land holdings, capitalized G&A andinterest and $2.5 million for increased seismic data and other geological andgeophysical expenditures. In connection with the acquisition we completed in December 2004,we are now required to make drilling advances to the operator of thoseproperties. Therefore a new item in 2005 is drilling advances related to ourQueen City properties of $4.3 million. The***

 

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***remaining capital expenditures wereassociated with computer hardware, office furniture and equipment for theexpansion into additional office space.***

 

***During the year ended December 31,2004, we used $89.4 million in investing activities. Capital expenditures forthe year ended December 31, 2004 were partially offset by $60,000 ofproceeds from the sale of one well and a gas cooler during the year. Capitalexpenditures of $45.7 million were attributable to the drilling of 49 grosswells, 40 of which were successful. Acquisition costs totaled $40.0 million forthe year ended December 31, 2004, which includes $39.8 million related tothe Contango Asset Acquisition. Other spending includes $2.6 million inexpenditures attributable to land holdings and $0.6 million for increasedseismic data and other geological and geophysical expenditures. The remainingcapital expenditures were associated with computer hardware, office furnitureand equipment for the expansion into additional office space.***

 

***During the year ended December 31,2003, we used $28.1 million in investing activities. Capital expenditures of$33.6 million for the year ended December 31, 2003, were partially offsetby $5.2 million of cash received in the Miller merger net of merger costsincurred and $0.3 million in proceeds from the sale of oil and gas propertiesduring 2003. Capital expenditures of $18.3 million were attributable to thedrilling 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 $0.8 million in expenditures was attributable to landholdings, including seismic data and other geological and geophysicalexpenditures. The remaining capital expenditures were associated with computerhardware and office equipment.***

 

Due to our active exploration, development andacquisition activities, we have experienced and expect to continue toexperience substantial working capital requirements. We currently anticipatecapital expenditures in 2006 to be approximately $98.0 million. Approximately $74.5million is allocated to our expected drilling and production activities; $16.5 millionis allocated to land, legal and seismic activities; and $7.0 million relates tocapitalized interest, G&A and other. We intend to fund these capitalexpenditures, and other commitments and working capital requirements withexpected cash flow from operations and, to the extent necessary, other sources.Should there be a change in our pricing or production assumptions, we believethat we have sufficient financial flexibility from other financing sources tomeet our financial obligations as they come due, and we would recommend to ourBoard an adjustment to our capital expenditures program accordingly so as toavoid unnecessary incremental borrowings that may be needed for acquisitions.We do not explicitly budget for acquisitions; however, we do expect to spendconsiderable effort evaluating acquisition opportunities. We expect to fundacquisitions through traditional reserve-based bank debt and/or the issuance ofequity and, if required, through additional debt and equity financings.

 

*Net Cash Provided By Financing Activities*

 

Cash flows provided by financing activities totaled$72.6 million for the year ended December 31, 2005. We had $81.0 millionin borrowings and $16.0 million in repayments under our credit facility. Weincurred loan costs of approximately $47,000 in amending our credit facility.In addition, we received $7.6 million in proceeds from the issuance of commonstock related to options and warrants exercised in 2005. The majority of thoseproceeds are related to the January 2005 underwriter exercise of theover-allotment option to the December 2004 common stock offering. Thefunds generated from that exercise were used to reduce debt early in 2005.

 

For the year ended December 31, 2004, cashflows provided by financing activities totaled $48.1 million including $27.0million in borrowings and $28.0 million in repayments under our creditfacility. In addition, we completed a public offering of common stock in December 2004that provided $47.2 million of net proceeds, after direct costs. For the yearended December 31, 2003, cash flows provided by financing activitiestotaled $2.9 million including $10.7 million in borrowings and $10.2 million inrepayments under our credit facility. In addition, we received $2.4 million inproceeds from the issuance of common stock related to options exercised in 2003as a result of the increase in our stock price.

 

The combination of unused debt capacity and ourcurrent shelf registration (see discussion below) should allow us the financialflexibility to continue to participate in acquisitions and complete our capitalprograms as we move into 2006. As of December 31, 2005, we had $25.0million of unused borrowing capacity under our credit facility.

 

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***Credit Facility***

 

On November 30, 2005, the Company amended itsThird Amended and Restated Credit Agreement (the “Credit Facility”), which ithad originally entered into in March 2004 (effective December 31,2003) and previously amended on May 31, 2005. The Credit Facility permitsborrowings up to the lesser of (i) the borrowing base and (ii) $150.0million. Effective November 2005, the borrowing base under the CreditFacility was increased from $70.0 million to $110.0 million as a result of the ChapmanRanch Field acquisitions and our drilling activities since the lastredetermination. Based on the increase, our available borrowing capacity at December 31,2005 was $25.0 million. We expect our borrowing base to be redetermined in April 2006and semiannually thereafter.

 

The Credit Facility matures December 31, 2007and is secured by substantially all of the Company’s assets. Borrowings underthe Credit Facility bear interest at a rate equal to prime plus 0.50% or LIBORplus 2.25%. As of December 31, 2005, our interest rate was 7.5%. As of December 31,2005, $85.0 million in borrowings were outstanding under the Credit Facilityand as of March 10, 2006 $94.0 million in borrowings were outstandingunder the Credit Facility.

 

The Credit Facility provides for certainrestrictions, including but not limited to, limitations on additionalborrowings, sales of oil and natural gas properties or other collateral, andengaging in merger or consolidation transactions. The Credit Facility alsoprohibits dividends and certain distributions of cash or properties and certainliens. The Credit Facility 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 CreditFacility Agreement, be at least $1.0 million. For the purposes of calculatingthe Working Capital ratio, the total of current assets is adjusted for unusedcapacity under the Credit Facility Agreement, and derivative financialinstruments and the total of current liabilities is adjusted for the currentportion of indebtedness under the Credit Facility Agreement, derivative financialinstruments 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 CreditFacility Agreement) as of such fiscal quarter to (b) an amount equal toconsolidated EBITDAX for the two quarters then ended times two, not be greaterthan 3.0 to 1.0.

 

Consolidated EBITDAX is a component of negotiatedcovenants with our lenders and is presented here as part of the Company’sdisclosure of its covenant obligations.

 

***Shelf Registration Statement***

 

During the second quarter 2005, we filed aregistration statement with the SEC which registered offerings of up to $390million of any combination of debt securities, preferred stock, common stock orwarrants for debt securities or equity securities of the Company. Net proceeds,terms and pricing of the offering of securities issued under the shelfregistration statement will be determined at the time of the offerings. Theshelf registration statement does not provide assurance that we will or couldsell any such securities. Our ability to utilize our shelf registrationstatement for the purpose of issuing, from time to time, any combination ofdebt securities, preferred stock, common stock or warrants for debt securitiesor equity securities will depend upon, among other things, market conditionsand the existence of investors who wish to purchase our securities at pricesacceptable to us. In connection with the filing of the 2005 registrationstatement, we deregistered the remaining shares then available for sale underour earlier $150 million shelf registration statement filed in 2004.

 

On December 21, 2004, we completed an offeringof 3.5 million shares of our common stock, which generated net proceeds to us,before direct costs of the offering, of $47.8 million. These funds were used tofinance the south Texas asset acquisition that closed on December 29, 2004with a final adjusted purchase price of $40.1 

 

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million,before other acquisition costs, and fund the costs of the offering and othergeneral corporate purposes. On January 5, 2005, the underwriters exercisedtheir 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 toreduce our outstanding debt. Each of these sales was made under our shelfregistration statement. At December 31, 2005, we had $390 millionremaining for issuance under our 2005 shelf registration statement.

 

***Off Balance Sheet Arrangements***

 

The Company currently does not have any off balancesheet arrangements.

 

***Contractual Cash Obligations***

 

The following table summarizes our contractual cashobligations as of December 31, 2005 by payment due date:

 
| ** **                                 | ** ** | **Total**               | ** ** | **Less than  1 Year** | ** ** | **1-3 Years** | ** ** | **4-5  Years** | ** ** | **After 5  Years** | ** ** |
|--------------------------------------------|------------|-------------------------|------------|---------------------------------|------------|--------------------|------------|----------------|------------|-------------------------|------------|
| ** **                                 | ** ** | **(In thousands)** | ** ** |
| Long-term  debt (1)                        |       | $                       | 85,000     |                            | $          | —             |       | $              | 85,000     |                    | $          | — |   | $ | — |   |
| Operating  leases                          |       | 6,171                   |       | 817                             |       | 2,461              |       | 1,620          |       | 1,273                   |       |
| Total  contractual cash obligations (2)(3) |       | $                       | 91,171     |                            | $          | 817                |       | $              | 87,461     |                    | $          | 1,620 |   | $ | 1,273 |   |

 

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(1)          Excludes amounts forinterest expense payable upon outstanding debt. Long-term outstanding debt underour credit facility is subject to floating interest rates (see Note 10 to ourconsolidated financial statements) and payable on the last day of each calendarmonth while any loan amounts remain outstanding.

(2)          We did not have anycapital leases or purchase obligations as of December 31, 2005.

(3)          We have not included ourARO Liability here because historically the actual cash outlay is minimizedsignificantly by the salvage value. In accordance with SFAS No. 143, we donot account for salvage value on our balance sheet, but we do not expect torealize the total value that we have accrued.

 

**Risk Management Activities – Derivatives and Hedging**

 

Due to the volatility of oil and natural gas prices,we may enter into, from time to time, price-risk management transactions(e.g., swaps, collars and floors) for a portion of our oil and natural gasproduction to achieve a more predictable cash flow, as well as to reduceexposure to commodity price fluctuations. While the use of these arrangements may limitour ability to benefit from increases in the price of oil and natural gas, italso reduces our potential exposure to adverse price movements. Ourarrangements, 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. We also use price-risk management transactions to protect forwardpricing as a bidding strategy with respect to acquisition offers and execution.None of these instruments are used for trading purposes. On a quarterly basis,our management sets all of our price-risk management policies, includingvolumes, types of instruments and counterparties. These policies areimplemented by management through the execution of trades by the ChiefFinancial Officer after consultation and concurrence by the President andChairman of the Board. Our Board of Directors monitors the Company’s price-riskmanagement policies and trades.

 

All of these price-risk management transactions areconsidered derivative instruments and accounted for in accordance with SFAS No. 133,*“Accounting for Derivative Instruments andHedging Activities”*. These derivative instruments are intended tohedge our price risk and may be considered hedges for economic purposes,but certain of these transactions may not qualify for special cash flowhedge accounting. Therefore, depending on the type of transaction and thecircumstances, different accounting treatment may apply to the timing andlocation of the income statement impact, but all derivatives are recorded onthe balance sheet at fair value. The following table provides additionalinformation regarding our various derivative and hedging transactions that wererecorded at fair value on the balance sheet as of December 31, 2005.

 

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| Fair value  of contracts outstanding at December 31, 2004                          |   | $          | 1,356,482  |   |
|-----------------------------------------------------------------------------------------|--------|------------|------------|--------|
| Contracts realized or otherwise settled  during the period                              |   | (2,987,666 | )          |
| Fair value of new contracts when entered  into during 2005:                             |   |       |       |
| Asset                                                                                   |   | —     |       |
| Liability                                                                               |   | (2,479,035 | )          |
| Changes in fair values attributable to  changes in valuation techniques and assumptions |   | —     |       |
| Other changes in fair values                                                            |   | 1,631,184  |       |
| Fair values of contracts outstanding at December 31,  2005                         |   | $          | (2,479,035 | )      |

 

Thefollowing table details the fair value of our commodity-based derivative andhedging contracts by year of maturity and valuation methodology as of December 31,2005.

 
| ** **                                           | ** ** | **Fair Value of Contracts at December 31, 2005** | ** ** |
|------------------------------------------------------|------------|-------------------------------------------------------------------------------------|------------|
| **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                                                |       | —                                                                              |       | — |   | — |   | — |   | — |   |
| Liability                                            |       | (2,479,035                                                                          | )          | — |   | — |   | — |   | (2,479,035 | ) |
| Prices based  on models and other valuation methods: |       | —                                                                              |       | — |   | — |   | — |   | — |   |
| Total                                                |       | $                                                                                   | (2,479,035 | ) | $ | — |   | $ | — |   | $ | — |   | $ | (2,479,035 | ) |

 

**Tax Matters**

 

At December 31, 2005, we have cumulative net operatingloss carryforwards (“NOLs”) for federal income tax purposes of approximately $55.8million, including $17.8 million of NOLs acquired in the Miller merger thatexpire beginning 2020 through 2024. These estimated NOLs assume that certainitems, primarily intangible drilling costs, have been written off for taxpurposes in the current year. However, we have not made a final determinationif an election will be made to capitalize all or part of these items fortax purposes in the future.

 

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

 

In December 2004, the FASB issued SFAS No. 123(R),*Share-Based Payment.* Thisstatement requires companies to measure the cost of employee services inexchange for an award of equity instruments based on a grant-date fair value ofthe award (with limited exceptions), and that cost must generally be recognizedover the vesting period. SFAS No. 123(R) amends the original SFAS No. 123and 95 that had allowed companies to choose between expensing stock options orshowing pro forma disclosure only. This statement eliminates the ability toaccount for share-based compensation transactions using APB Opinion No. 25.We currently account for our stock-based compensation plans under theprinciples prescribed by APB Opinion No. 25. Accordingly, no stock optioncompensation cost is reflected in net income, as all options granted under theplan had an exercise price equal to the market value of the underlying commonstock on the date of grant. The adoption of SFAS No. 123(R) will impactour results of operations, but will have no impact on our overall financialposition. In March 2005, the SEC issued SAB No. 107. Among otherthings, SAB No. 107 provides interpretive guidance related to theinteraction between SFAS No. 123(R) and certain SEC rules andregulations, as well as provides the SEC staff’s views regarding the valuationof share-based payment arrangements for public companies. SFAS No. 123(R)was to become effective as of the beginning of the first interim or annualreporting period that begins after June 15, 2005, but on April 14,2005, the SEC issued press release 2005-57, which amends the compliance date ofSFAS No. 123(R) until fiscal years beginning after June 15, 2005. Weanticipate adopting the provisions of SFAS No. 123(R) in the firstquarter of 2006 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 immaterial dueto the fact that we have not issued options since April 2004 and therewill only be a minimal number of unvested options as of our adoption date. SFASNo. 123(R) also 

 

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requiresthe benefits of tax deductions in excess of recognized compensation cost bereflected as a financing cash flow, rather than as an operating cash flow ascurrently required.

 

In December 2004, the FASB issued SFAS No. 153,*Exchanges of Nonmonetary Assets, an amendment of APBOpinion No. 29*. SFAS No. 153 is based on the principlethat exchanges of nonmonetary assets should be measured based on the fair valueof the assets exchanged. APB Opinion No. 29, *Accountingfor Nonmonetary Transactions*, provided an exception to its basicmeasurement principle (fair value) for exchanges of similar productive assets.Under APB Opinion No. 29, an exchange of a productive asset for a similarproductive asset was based on the recorded amount of the asset relinquished.SFAS No. 153 eliminates the exception for nonmonetary exchanges of similarproductive assets and replaces it with a general exception for exchanges ofnonmonetary assets that do not have commercial substance. Nonmonetary exchangehas commercial substance if the future cash flows of the entity are expected tochange significantly as a result of the exchange. SFAS No. 153 iseffective for fiscal periods beginning after June 15, 2005. The adoptionof SFAS No. 153 is not expected to have a material effect on ourconsolidated financial position, results of operations or cash flows.

 

In March 2005, the FASB issued FASBInterpretation No. 47, *Accounting forConditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143*(“FIN 47”). FIN 47 clarifies that the term, “conditional asset retirementobligation” as used in SFAS No. 143, *Accountingfor Asset Retirement Obligations*, refers to a legal obligation toperform an asset retirement activity in which the timing and/or method ofsettlement are conditional upon a future event that may or may not bewithin the control of the entity. Even though uncertainty about the timingand/or method of settlement exists and may be conditional upon a futureevent, the obligation to perform the asset retirement activity isunconditional. Accordingly, an entity is required to recognize a liability forthe fair value of a conditional asset retirement obligation if the fair valueof the liability can be reasonably estimated. Uncertainty about the timingand/or method of settlement of a conditional asset retirement obligation shouldbe factored into the measurement of the liability when sufficient informationexists. The fair value of a liability for the conditional asset retirementobligation should be recognized when incurred generally upon acquisition,construction, or development or through the normal operation of the asset. SFASNo. 143 acknowledges that in some cases, sufficient information may notbe available to reasonably estimate the fair value of an asset retirementobligation. FIN 47 also clarifies when an entity would have sufficientinformation to reasonably estimate the fair value of an asset retirementobligation. FIN 47 is effective for fiscal years ending after December 15,2005. Retrospective application for interim financial information is permittedbut is not required. The adoption of FIN 47 is not expected to have a materialeffect on our consolidated financial position, results of operations or cashflows.

 

In June 2005, the FASB issued SFAS No. 154,*Accounting Changes and Error Corrections*,*a replacement of Accounting Principles Board (“APB”)Opinion No. 20 and FASB Statement No. 3,*which changes therequirements for the accounting for and reporting of a change in accountingprinciple. It also applies to changes required by an accounting pronouncementin the unusual instance that the pronouncement does not include specifictransition provisions. Application is effective for accounting changes andcorrection of errors made in fiscal years beginning after December 15,2005. The adoption of SFAS No. 154 is not expected to have a materialeffect on our consolidated financial position, results of operations or cashflows.

 

InFebruary 2006, the FASB issued SFAS No. 155, *Accountingfor Certain Hybrid Financial Instruments,*which improves financialreporting by eliminating the exemption from applying SFAS No. 133 tointerests in securitized financial assets so that similar instruments areaccounted for similarly regardless of the form of the instruments andallows a preparer to elect fair value measurement at acquisition, at issuance,or when a previously recognized financial instrument is subject to aremeasurement (new basis) event, on an instrument-by-instrument basis, in casesin which a derivative would otherwise have to be bifurcated. Providing a fairvalue measurement election also results in more financial instruments beingmeasured at what the FASB regards as the most relevant attribute for financialinstruments, fair value. SFAS No. 155 is effective for all financialinstruments acquired or issued after the beginning of an entity’s first fiscalyear that begins after September 15, 2006. We are currently evaluating theimpact of this standard on our financial position, results of operations andcash flows.

 

***ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURESABOUT MARKET RISK***

 

We are exposed to marketrisk from changes in interest rates and commodity prices. We use a creditfacility, which has a floating interest rate, to finance a portion of ouroperations. We are not subject to fair value risk resulting from changes in ourfloating interest rates. The use of floating rate debt instruments provides abenefit due to downward interest rate movements but does not limit us toexposure from future increases in interest rates. Based 

 

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onthe year-end December 31, 2005 outstanding borrowings and our applicableinterest rate of 7.5%, a 10% change in interest rate would result in anincrease or decrease of interest expense of approximately $0.6 million on anannual basis.

 

In the normal course ofbusiness we enter into hedging transactions, including commodity price collars,swaps and floors to mitigate our exposure to commodity price movements, but notfor trading or speculative purposes. During 2005, we put in place severalnatural gas and crude oil collars for a portion of our 2006 production toachieve a more predictable cash flow. Please refer to Note 9 to ourconsolidated financial statements. While the use of these arrangements may limitthe benefit to us of increases in the price of oil and natural gas, it alsolimits the downside risk of adverse price movements. The following is a list ofhedge and derivative contracts outstanding at December 31, 2005:

 
| **Transaction  Date** | ** ** | **Transaction  Type** | ** ** | **Beginning** | ** ** | **Ending** | ** ** | **Price  Per Unit** | ** ** | **Volumes Per  Day** | ** ** | **Fair Value  Outstanding as of  December 31, 2005** | ** ** |
|-----------------------|------------|-----------------------|------------|---------------|------------|------------|------------|--------------------------|------------|---------------------------|------------|-------------------------------------------------------------------------------|------------|
| ***Natural Gas:***    |       |                  |       |          |       |       |       |                     |       |                      |       |                                                                          |       |
| 08/05                 |       | Collar (1)            |       | 01/01/06      |       | 12/31/06   |       | $7.00-$10.50             |       | 10,000 MMbtu              |       | $                                                                             | (2,497,823 | ) |
|                  |       |                  |       |          |       |       |       |                     |       |                      |       |                                                                          |       |
| 08/05                 |       | Collar (1)            |       | 01/01/06      |       | 12/31/06   |       | $7.00-$16.10             |       | 10,000 MMbtu              |       | (137,077                                                                      | )          |
| ***Crude Oil:***      |       |                  |       |          |       |       |       |                     |       |                      |       |                                                                          |       |
| 08/05                 |       | Collar (2)            |       | 01/01/06      |       | 12/31/06   |       | $55.00-$80.00            |       | 400 Bbl                   |       | 155,865                                                                       |       |
|                  |       |                  |       |          |       |       |       |                     |       |                      |       | $                                                                             | (2,479,035 | ) |

 

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(1)                Ourcurrent 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)                Hedge accountingis not applied to our 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 revenue.

 

At December 31, 2005,the fair value of the outstanding hedge and derivative contracts was a net liabilityof approximately $2.5 million (See *ITEM7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OFOPERATIONS –*RISK MANAGEMENT ACTIVITIES – DERIVATIVES AND HEDGING*”)*. A 10% change inthe commodity price per unit, as long as the price is either above the ceilingor below the floor price of each contract, would cause the fair value total ofthe outstanding net asset position to increase or decrease by approximately $0.3million.

 

***ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA***

 

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

 

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

 

None.

 

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

 

**(a) Disclosure Controls and Procedures.** We maintain disclosure controls andprocedures that are designed to provide reasonable assurance that informationrequired to be disclosed by us in the reports that we file or submit to theSecurities and Exchange Commission (“SEC”) under the Securities Exchange Act of1934, as amended (the “Exchange Act”), is recorded, processed, summarized andreported within the time periods specified by the SEC’s rules and forms,and that information is accumulated and communicated to our management,including our Chief Executive Officer and Chief Financial Officer, asappropriate to allow timely decisions regarding required disclosure.

 

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Inaccordance with Exchange Act Rules 13a-15 and 15d-15, we carried out anevaluation, under the supervision and with the participation of management,including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”),of the effectiveness of our disclosure controls and procedures as of the end ofthe period covered by this report. As described below under Management’s AnnualReport on Internal Control over Financial Reporting, our CEO and CFO haveconcluded that, as of the end of the period covered by this Annual Report on Form 10-K,the Company’s disclosure controls and procedures were effective to providereasonable assurance that information required to be disclosed in our reportsfiled or submitted under the Exchange Act is recorded, processed, summarizedand reported within the time periods specified in the SEC’s rules andforms.

 

BDOSeidman, LLP’s audit report, dated March 10, 2006, expressed anunqualified opinion on our consolidated financial statements and its assessmentof Management’s Annual Report on Internal Control over Financial Reporting isincluded herein under paragraph (e).

 

**(b) Management’s Annual Report on InternalControl over Financial Reporting.**Management, including the CEO and CFO, has the responsibility forestablishing and maintaining adequate internal control over financialreporting, as defined in the Exchange Act, Rule 13a-15(f). Internalcontrol over financial reporting is a process designed by, or under thesupervision of, the Company’s principal executive and principal financialofficers, or persons performing similar functions and effected by the Company’sBoard of Directors, management and other personnel, to provide reasonableassurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with accountingprinciples generally accepted in the United States of America (“GAAP”). Becauseof its inherent limitations, internal control over financial reporting may notprevent or detect misstatements. In addition, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls may becomeinadequate or insufficient because of changes in operating conditions, or thatthe degree of compliance with the policies or procedures may deteriorate.

 

Acontrol deficiency exists when the design or operation of a control does notallow management or employees, in the ordinary course of performing theirassigned functions, to prevent or detect misstatements on a timely basis. Asignificant deficiency is a control deficiency, or combination of controldeficiencies, that adversely affects the Company’s ability to initiate,authorize, record, process, or report external financial data reliably inaccordance with GAAP, such that there is a more than remote likelihood that amisstatement of the Company’s annual or interim financial statements that ismore than inconsequential will not be prevented or detected. A materialweakness is a control deficiency, or combination of control deficiencies, thatresults in more than a remote likelihood that a material misstatement of theannual or interim financial statements will not be prevented or detected.

 

Managementassessed internal control over financial reporting of the Company andsubsidiaries as of December 31, 2005. The Company’s management conductedits assessment in accordance with the *InternalControl – Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission (“COSO”). Management has concluded,that as of December 31, 2005, the internal control over financialreporting was effective as of December 31, 2005, excluding the acquisitionof Cinco Energy Corporation (“Cinco”) (see discussion below under paragraph(c)).

 

BDOSeidman, LLP, the independent registered public accounting firm who alsoaudited the Company’s consolidated financial statements, has issued its ownattestation report on management’s assessment of the effectiveness of internalcontrol over financial reporting as of December 31, 2005, which is filedherewith.

 

**(c) Exclusion of Cinco.**The acquisition of Cinco met the SEC’s criteriaof being a significant acquisition. For additional information regarding theCinco acquisition, see *ITEM 7. “MANAGEMENT’SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS –ACQUISITIONS AND DIVESTIURES”*and Note 6 to the consolidatedfinancial statements of this report.

 

On June 22, 2004, the Office of the ChiefAccountant of the SEC issued guidance regarding the reporting of internalcontrols over financial reporting in connection with a major acquisition. On October 6,2004, the SEC revised its guidance to include expectations of quarterlyreporting updates of new internal controls and the status of the controlsregarding any exempted businesses. 

 

The effect of this guidance from the SEC isthat, although Management’s Annual Report on Internal Control over FinancialReporting generally must include controls at all consolidated entities, suchreport need not include controls at a recently acquired consolidated entity ifit is not possible for an assessment of the controls at such entity to beperformed in the period between the consummation date and the date ofManagement’s assessment and, among other things, reference is made to suchexclusion in Management’s Annual Report on Internal Control over FinancialReporting. 

 

In accordance with this guidance from the SEC, duringthe fourth quarter of 2005, management concluded that it was appropriate toexclude the Cinco assets from the scope of Management’s Annual Report on Internal Control over Financial Reportingfor the year ended December 31, 2005. The exclusion was made because giventhe time required to test the operating effectiveness of such controls and thedue date for the Section 404 attestation, it was not practical from atiming or resource 

 

55

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standpoint for Edge to conduct a thoroughassessment between the closing of the acquisition on November 30, 2005 andyear end 2005. Cinco was a privately owned company and had not previouslyimplemented the testing and documentations requirements of Section 404 ofthe Sarbanes-Oxley Act of 2002. Cinco utilized the same financial accounting(i.e. general ledger) computer system as Edge, which allowed certainefficiencies for integrating the data and accounting, but obtaining an independentreview of such computer systems and controls at Cinco was not feasible withinthe time frame. Edge did not assume any of the personnel or processes of Cincoand is in the process of integrating the operations and processes related toits internal control structure into Edge’s. Edge expects that this effort willbe completed in early 2006 and that Cinco will be included in the assessmentand documentation of internal controls for the year ended December 31,2006.

 

**(d) Changes in Internal Control Over FinancialReporting.**Other thanthose discussed under paragraph (c), there have not been any changes in theCompany’s internal control over financial reporting during the fiscal quarterended December 31, 2005 that have materially affected, or are reasonably likelyto materially affect, the Company’s internal control over financial reporting.

 

**(e) Report of Independent Registered PublicAccounting Firm**

 

Boardof Directors and StockholdersEdge Petroleum Corporation

Houston,Texas

 

We have audited management’sassessment, included in the accompanying Form 10-K, that Edge PetroleumCorporation maintained effective internal control over financial reporting asof December 31, 2005, based on criteriaestablished in*Internal Control—IntegratedFramework* issued by the Committee of Sponsoring Organizations of theTreadway Commission (COSO). Edge Petroleum Corporation’s management isresponsible for maintaining effective internal control over financial reportingand for its assessment of the effectiveness of internal control over financialreporting. Our responsibility is to express an opinion on management’sassessment and an opinion on the effectiveness of the company’s internalcontrol over financial reporting based on our audit.

 

We conducted our audit inaccordance with the standards of the Public Company Accounting Oversight Board(United States). Those standards require that we plan and perform theaudit to obtain reasonable assurance about whether effective internal controlover financial reporting was maintained in all material respects. Our auditincluded obtaining an understanding of internal control over financialreporting, evaluating management’s assessment, testing and evaluating thedesign and operating effectiveness of internal control, and performing such otherprocedures as we considered necessary in the circumstances. We believe that ouraudit provides a reasonable basis for our opinion.

 

A company’s internal controlover financial reporting is a process designed to provide reasonable assuranceregarding the reliability of financial reporting and the preparation offinancial statements for external purposes in accordance with generallyaccepted accounting principles. A company’s internal control over financialreporting includes those policies and procedures that (1) pertain to themaintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (2) providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally acceptedaccounting principles, and that receipts and expenditures of the company arebeing made only in accordance with authorizations of management and directorsof the company; and (3) provide reasonable assurance regarding preventionor timely detection of unauthorized acquisition, use, or disposition of thecompany’s assets that could have a material effect on the financial statements.

 

Because of its inherentlimitations, internal control over financial reporting may not prevent ordetect misstatements. Also, projections of any evaluation of effectiveness tofuture periods are subject to the risk that controls may become inadequatebecause of changes in conditions, or that the degree of compliance with thepolicies or procedures may deteriorate.

 

As describedin Management’s Annual Report on Internal Control over Financial Reporting,management has excluded Cinco Energy Corporation (“Cinco”) from its assessmentof internal control over financial reporting as of December 31, 2005 becauseCinco was acquired by the Company in a purchase business combination onNovember 30, 2005.  Accordingly, we havealso excluded Cinco from our audit of internal control over financial reportingas of December 31, 2005.  Cinco, which isincluded in the 2005 consolidated financial statements of Edge PetroleumCorporation, constituted approximately 17% of total assets at December 31, 2005and less than 1% of total revenues for the year ended December 31, 2005.

 

In our opinion, management’sassessment that Edge Petroleum Corporation maintained effective internalcontrol over financial reporting as of December 31, 2005, is fairlystated, in all material respects, based on *Internal Control - Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO). Also in our opinion,Edge Petroleum Corporation maintained, in all material respects, effectiveinternal control over financial reporting as of December 31, 2005, based on*Internal Control—Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO).

 

56

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Wehave also audited, in accordance with the standards of the Public CompanyAccounting Oversight Board (United States), the consolidated balance sheets ofEdge Petroleum Corporation as of December 31, 2005 and 2004 and therelated consolidated statements of income and comprehensive income,stockholders’ equity, and cash flows for each of the three years in the periodended December 31, 2005 and our report dated March 10, 2006 expressed an unqualified opinionthereon.

 
| /S/ BDO  SEIDMAN, LLP |   |
|-----------------------|--------|

BDOSeidman, LLP

Houston,TX

March 10,2006

 

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

 

None.

 

57

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**PART III**

 

***ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THEREGISTRANT***

 

The information regarding directors and executiveofficers required under *ITEM 10* will becontained within the definitive Proxy Statement for the Company’s 2006 AnnualMeeting of Shareholders (the “Proxy Statement”) under the headings “Election ofDirectors,” “Standing Committees, Board Organization, Director Nominations andMeetings” and “Compliance with Section 16(a) of the Exchange Act” andis incorporated herein by reference. The Proxy Statement will be filed pursuantto Regulation 14A with the Securities and Exchange Commission not later than120 days after December 31, 2005. Pursuant to Item 401(b) ofRegulation S-K certain of the information required by this item with respect toour executive officers is set forth in Part I of this report.

 

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

 

***ITEM 11. EXECUTIVE COMPENSATION***

 

The information required by *ITEM 11*will be contained in the Proxy Statement under the headings “Executive Compensation,” “Summary CompensationTable,” “Option/SAR Grants,” “Option/SAR Exercises and 2004 Year-End Option/SARValues,” “401(k) Employee Savings Plan,” “Employment Agreements and Change ofControl Agreements,” “Compensation Committee Interlocks and InsiderParticipation,” “Performance Graph” and “Compensation Committee Report onExecutive Compensation” and is incorporated herein by reference.

 

***ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIALOWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS***

 

The information required by *ITEM 12*will be contained in the Proxy Statement under the headings “Security Ownershipof Certain Beneficial Owners and Management” and “Equity Compensation PlanInformation” and is incorporated herein by reference.

 

***ITEM 13. CERTAIN RELATIONSHIPS AND RELATEDTRANSACTIONS***

 

The information required by *ITEM 13*will be contained in the Proxy Statement under the heading “CertainTransactions “ and is incorporated herein by reference.

 

***ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES***

 

The information required by *ITEM 14*will be contained in the Proxy Statement under the heading “Approval ofAppointment of Independent Public Accountants” and is incorporated herein byreference.

 

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**PART IV**

 

***ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES***

 
| (a)    |   | Financial Statements and Schedules:                                      |
|--------|--------|--------------------------------------------------------------------------|
|   |   | 1.                                                                       |   | Financial Statements: See Index to the Consolidated Financial  Statements and Supplementary Information immediately following the signature page of  this report. |
|   |   |                                                                     |   |   |
|   |   | 2.                                                                       |   | Financial Statement Schedule: See Index to the Consolidated Financial  Statements and Supplementary Information immediately following the signature page of  this report. |
|   |   |                                                                     |   |   |
| (b)    |   | Exhibits: The following documents are filed as exhibits to this  report: |
|   |   | 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 as of October 7, 2004 (Incorporated by  reference from exhibit 2.1 to the Company’s Current Report on Form 8-K  filed October 12, 2004). |
|   |   |                                                                     |   |   |
|   |   | 2.4 —                                                               |   | Purchase and Sale Agreement, dated as of September 21, 2005  among Pearl Energy Partners, Ltd., and Cibola Exploration Partners, L.P., as  Sellers; and Edge Petroleum Exploration Company as Buyer and Edge Petroleum  Corporation as Guarantor (Incorporated by reference from exhibit 2.1 to  the Company’s Current Report on Form 8-K filed October 19, 2005). |
|   |   |                                                                     |   |   |
|   |   | 2.5 —                                                               |   | Stock Purchase Agreement by and among Jon L. Glass, Craig D. Pollard,  Leigh T. Prieto, Yorktown Energy Partners V, L.P., Yorktown Energy Partners  VI, L.P., Cinco Energy Corporation, and Edge Petroleum Exploration Company  and Edge Petroleum Corporation, dated as of September 21, 2005  (Incorporated by reference from exhibit 2.5 to the Company’s Quarterly  Report on Form 10-Q for the quarterly period ended September 30,  2005). |
|   |   |                                                                     |   |   |
|   |   | 2.6 —                                                               |   | Letter Agreement dated November 18, 2005 by and among Edge  Petroleum Exploration Company, Cinco Energy Corporation and Sellers  (Incorporated by reference from exhibit 2.02 to the Company’s Current  Report on Form 8-K filed December 6, 2005). Pursuant to Item 601(b)(2) of  Regulation S-K, the Company had omitted certain Schedules to the Letter  Agreement (all of which are listed therein) from this Exhibit 2.6. It  hereby agrees to furnish a supplemental copy of any such omitted item to the  SEC on its request. |
|   |   |                                                                     |   |   |
|   |   | 3.1 —                                                               |   | Restated Certificate of Incorporation of the Company effective January 27,  1997 (Incorporated by reference from exhibit 3.1 to the Company’s  Current Report on Form 8-K filed April 29, 2005). |
|   |   |                                                                     |   |   |
|   |   | 3.2 —                                                               |   | Certificate of Amendment to the Restated Certificate of Incorporation  of the Company effective January 31, 1997 (Incorporated by reference  from exhibit 3.2 to the Company’s Current Report on Form 8-K filed April 29,  2005). |
|   |   |                                                                     |   |   |
|   |   | 3.3  —                                                              |   | Certificate  of Amendment to the Restated Certificate of Incorporation of the Company  effective April 27, 2005 (Incorporated by reference from exhibit 3.3  to the Company’s Current Report on Form 8-K filed April 29, 2005). |
|   |   |                                                                     |   |   |
|   |   | 3.4 —                                                               |   | 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). |
|        |        |                                                                          |  |  |  |  |

 

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|   |   | 3.5 —       |   | 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).                                                                                                                                                                                                                                                                                                                                               |
|--------|--------|------------------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |             |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
|   |   | 3.6 —       |   | 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 —       |   | Agreement and Amendment No. 1 to Third Amended and Restated  Credit Agreement dated May 31, 2005 among Edge Petroleum Corporation,  Edge Petroleum Exploration Company, Edge Petroleum Operating Company, Inc.,  Miller Exploration Company and Miller Oil Corporation, as borrowers, the  lenders thereto and Union Bank of California, N.A., a national banking  association, as agent for the lenders (Incorporated by reference from Exhibit 4.2  to the Company’s Quarterly Report on Form 10-Q for the quarterly period  ended June 30, 2005). |
|   |   |             |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
|   |   | *4.3 —      |   | Agreement and Amendment No. 2 to the Third Amended and Restated  Credit Agreement dated November 30, 2005 among Edge Petroleum  Corporation, Edge Petroleum Exploration Company, Edge Petroleum Operating  Company, Inc., Miller Oil Corporation, Miller Exploration Company, and Cinco  Energy Corporation, as borrowers, the lenders thereto and Union Bank of  California, N.A., a national banking association, as Agent.                                                                                                                                                 |
|   |   |             |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
|   |   | 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).                                                                                                                                                                                                                                                                                                                                        |

 

60

----

 
|   |   | †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 therein (Incorporated by reference from exhibit 10.4  to the Company’s Quarterly Report on Form 10-Q for the quarterly period  ended September 30, 1999).                                                                   |
|   |   |               |   |                                                                                                                                                                                                                                                                                                                                                  |
|   |   | †10.8—   |   | 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).                                                                   |
|   |   |               |   |                                                                                                                                                                                                                                                                                                                                                  |
|   |   | †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 2005 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.                                                                                                                                                                           |

 

61

----

 
|   |   | *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, 2005.                                                                           |
|   |   |        |   |                                                                                                                                                                          |
|   |   | *99.2— |   | Summary of Reserve Report of W. D. Von Gonten & Co.  Petroleum Engineers as of December 31, 2005.                                                               |

 

----

* Filed herewith.

†Denotes management or compensatory contract, arrangement or agreement, or asummary or description thereof.

 

62

----

 

**SIGNATURES**

 

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

 
| ** ** | **Edge  Petroleum Corporation** |
|------------|---------------------------------|
| ** ** | ** **                      |
| ** ** | ** By**                    | /S/ John W. Elias | ** ** |
| ** ** | ** **                      | John W. Elias | ** ** |
| ** ** | ** **                      | Chief Executive Officer and Chairman of the  Board | ** ** |
| ** ** | ** **                      | Date: March 14, 2006 | ** ** |

 

Pursuant to the requirements of the SecuritiesExchange Act of 1934, this report has been signed below by the followingpersons on behalf of the registrant and in the capacities and on the datesindicated.

 
| By     | /S/ John W. Elias                                                                                          |   | Date:  March 14, 2006 |
|--------|------------------------------------------------------------------------------------------------------------|--------|----------------------------|
|   | John W. Elias                                                                                              |   |                       |
|   | Chief Executive Officer and Chairman of the  Board(Principal Executive Officer)                            |   |                       |
|   |                                                                                                       |   |                       |
| By     | /S/ Michael G. Long                                                                                        |   | Date:  March 14, 2006 |
|   | Michael G. Long                                                                                            |   |                       |
|   | Executive Vice President andChief Financial Officer(Principal Financial and Principal  Accounting Officer) |   |                       |
|   |                                                                                                       |   |                       |
| By     | /S/ Thurmon M. Andress                                                                                     |   | Date:  March 14, 2006 |
|   | Thurmon Andress                                                                                            |   |                       |
|   | Director                                                                                                   |   |                       |
|   |                                                                                                       |   |                       |
| By     | /S/ Vincent S. Andrews                                                                                     |   | Date:  March 14, 2006 |
|   | Vincent Andrews                                                                                            |   |                       |
|   | Director                                                                                                   |   |                       |
|   |                                                                                                       |   |                       |
| By     | /S/ Jonathan Clarkson                                                                                      |   | Date:  March 14, 2006 |
|   | Jonathan Clarkson                                                                                          |   |                       |
|   | Director                                                                                                   |   |                       |
|   |                                                                                                       |   |                       |
| By     | /S/ Michael Creel                                                                                          |   | Date:  March 14, 2006 |
|   | Michael Creel                                                                                              |   |                       |
|   | Director                                                                                                   |   |                       |
|   |                                                                                                       |   |                       |
| By     | /S/ Stanley S. Raphael                                                                                     |   | Date:  March 14, 2006 |
|   | Stanley S. Raphael                                                                                         |   |                       |
|   | Director                                                                                                   |   |                       |
|   |                                                                                                       |   |                       |
| By     | /S/ John Sfondrini                                                                                         |   | Date:  March 14, 2006 |
|   | John Sfondrini                                                                                             |   |                       |
|   | Director                                                                                                   |   |                       |
|   |                                                                                                       |   |                       |
| By     | /S/ Robert W. Shower                                                                                       |   | Date:  March 14, 2006 |
|   | Robert W. Shower                                                                                           |   |                       |
|   | Director                                                                                                   |   |                       |
|   |                                                                                                       |   |                       |
| By     | /S/ David F. Work                                                                                          |   | Date:  March 14, 2006 |
|   | David F. Work                                                                                              |   |                       |
|   | Director                                                                                                   |   |                       |

 

63

----

##### ** **

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

##### ** **

Index to Consolidated Financial Statements and SupplementaryInformation

 
| **CONSOLIDATED  FINANCIAL STATEMENTS**                                                                      | ** ** |
|-------------------------------------------------------------------------------------------------------------|------------|
| ** **                                                                                                  | ** ** |
| Audited Financial Statements:                                                                               |       |
| Report of Independent  Registered Public Accounting Firm                                                    |       |
|                                                                                                        |       |
| Consolidated  Balance Sheets as of December 31, 2005 and 2004                                               |       |
|                                                                                                        |       |
| Consolidated  Statements of Operations for the Years Ended                                                  |       |
| December 31, 2005, 2004 and  2003                                                                           |       |
|                                                                                                        |       |
| Consolidated  Statements of Comprehensive Income for the Years Ended                                        |       |
| December  31, 2005, 2004 and 2003                                                                           |       |
|                                                                                                        |       |
| Consolidated  Statements of Cash Flows for the Years Ended                                                  |       |
| December  31, 2005, 2004 and 2003                                                                           |       |
|                                                                                                        |       |
| Consolidated  Statements of Stockholders’ Equity for the Years Ended  December 31, 2005, 2004 and 2003 |       |
|                                                                                                        |       |
| Notes  to Consolidated Financial Statements                                                                 |       |
|                                                                                                        |       |
| Unaudited Information:                                                                                      |       |
| Supplementary Information to Consolidated  Financial Statements                                             |       |

 

**CONSOLIDATEDFINANCIAL STATEMENT SCHEDULES**

 

Allschedules for which provision is made in the applicable accounting regulationsof the Securities and Exchange Commission are not required under the relatedinstructions or are inapplicable and therefore have been omitted.

 

F-1

----

 

**Report of Independent Registered PublicAccounting Firm**

 

Boardof Directors and StockholdersEdge Petroleum Corporation

Houston,Texas

 

We have audited the accompanying consolidated balancesheets of Edge Petroleum Corporation as of December 31, 2005 and 2004 and the related consolidated statements of income andcomprehensive income, stockholders’ equity, and cash flows for eachof the three years in the period ended December 31, 2005. These financial statements arethe responsibility of the Company’s management. Our responsibility is to expressan opinion on these financial statements based on our audits.

 

We conducted ouraudits in accordance with the standards of the Public Company AccountingOversight Board (United States). Those standards require that weplan and perform the audit to obtain reasonableassurance about whether the financial statements are free of materialmisstatement. An audit includes examining, on a test basis, evidence supportingthe amounts and disclosures in the financial statements, assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financialstatement presentation. We believe that our auditsprovide a reasonable basis for our opinion.

 

In our opinion,the consolidated financial statements referred toabove present fairly, in all material respects, the financial position of EdgePetroleum Corporation at December 31, 2005 and 2004, and the results of itsoperations and its cash flows for each of the three years in the period ended December 31, 2005**,** in conformity with accountingprinciples generally accepted in the United States of America.

 

We also have audited, inaccordance with the standards of the Public Company Accounting Oversight Board(United States), the effectiveness of Edge Petroleum Corporation’s internalcontrol over financial reporting as of December 31, 2005, based on criteriaestablished in *Internal Control – IntegratedFramework*issued by the Committee of Sponsoring Organizations of theTreadway Commission (COSO) and our report dated March 10, 2006 expressed anunqualified opinion thereon.

 
| /S/ BDO Seidman, LLP |   |
|---------------------------|--------|

BDO Seidman, LLP

 

Houston, Texas

March 10, 2006

 

F-2

----

 

### **EDGE PETROLEUM CORPORATION**

 

**CONSOLIDATEDBALANCE SHEETS**

 
| ** **                                                                                                                                                                                                           | ** ** | **December 31,** | ** **  |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------|-------------|
| ** **                                                                                                                                                                                                           | ** ** | **2005**              | ** **  | **2004** | ** ** |
| **ASSETS**                                                                                                                                                                                                           |       |                  |        |   |   |
| CURRENT ASSETS:                                                                                                                                                                                                      |       |                  |        |   |   |
| Cash and cash equivalents                                                                                                                                                                                            |       | $                     | 666,332     |   | $ | 2,267,423 |   |
| Accounts receivable, trade, net of  allowance of $525,248 as of December 31, 2005 and 2004                                                                                                                           |       | 24,980,196            |        | 12,756,097 |   |
| Accounts receivable, joint interest owners  and other, net of allowance of $4,771 and $82,000 as of December 31, 2005 and  2004                                                                                      |       | 2,100,305             |        | 5,911,073 |   |
| Deferred income taxes                                                                                                                                                                                                |       | 2,517,659             |        | 660,223 |   |
| Derivative financial instruments                                                                                                                                                                                     |       | —                |        | 1,824,790 |   |
| Other current assets                                                                                                                                                                                                 |       | 6,436,693             |        | 1,445,923 |   |
| Total current assets                                                                                                                                                                                                 |       | 36,701,185            |        | 24,865,529 |   |
| PROPERTY AND EQUIPMENT, Net – full cost  method of accounting for oil and natural gas properties (including  unevaluated costs of $36.9 million and $15.5 million at December 31, 2005 and  2004, respectively) |       | 306,455,515           |        | 165,840,345 |   |
| OTHER ASSETS                                                                                                                                                                                                         |       | 223,175               |        | 284,280 |   |
| TOTAL ASSETS                                                                                                                                                                                                         |       | $                     | 343,379,875 |   | $ | 190,990,154 |   |
|                                                                                                                                                                                                                 |       |                  |        |   |   |
| **LIABILITIES  AND STOCKHOLDERS’ EQUITY**                                                                                                                                                                       |       |                  |        |   |   |
| CURRENT LIABILITIES:                                                                                                                                                                                                 |       |                  |        |   |   |
| Accounts payable, trade                                                                                                                                                                                              |       | $                     | 5,570,625   |   | $ | 3,141,235 |   |
| Accrued liabilities                                                                                                                                                                                                  |       | 17,894,439            |        | 12,105,694 |   |
| Derivative financial instruments                                                                                                                                                                                     |       | 2,479,035             |        | 468,308 |   |
| Accrued interest payable                                                                                                                                                                                             |       | 17,466                |        | — |   |
| Asset retirement obligation – current  portion                                                                                                                                                                  |       | 202,469               |        | 193,647 |   |
| Total current liabilities                                                                                                                                                                                            |       | 26,164,034            |        | 15,908,884 |   |
| ASSET RETIREMENT OBLIGATION – long-term  portion                                                                                                                                                                |       | 2,563,777             |        | 1,995,441 |   |
| DEFERRED TAX LIABILITY                                                                                                                                                                                               |       | 37,896,759            |        | 2,618,934 |   |
| LONG-TERM DEBT                                                                                                                                                                                                       |       | 85,000,000            |        | 20,000,000 |   |
| Total liabilities                                                                                                                                                                                                    |       | 151,624,570           |        | 40,523,259 |   |
| 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; 60,000,000  shares authorized; 17,216,776 and 16,535,901 shares issued and outstanding at  December 31, 2005 and 2004, respectively                                                   |       | 172,168               |        | 165,359 |   |
| Additional paid-in capital                                                                                                                                                                                           |       | 137,841,756           |        | 126,957,059 |   |
| Retained earnings                                                                                                                                                                                                    |       | 55,454,066            |        | 22,095,807 |   |
| Accumulated other comprehensive income  (loss)                                                                                                                                                                       |       | (1,712,685            | )           | 1,248,670 |   |
| Total stockholders’ equity                                                                                                                                                                                      |       | 191,755,305           |        | 150,466,895 |   |
| TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY                                                                                                                                                                      |       | $                     | 343,379,875 |   | $ | 190,990,154 |   |

 

See accompanying notes to the consolidated financial statements.

 

F-3

----

 

### **EDGE PETROLEUM CORPORATION**

 

**CONSOLIDATEDSTATEMENTS OF OPERATIONS**

 
| ** **                                                                        | ** ** | **Year Ended December 31,** | ** **  |
|-----------------------------------------------------------------------------------|------------|--------------------------------------------|-------------|
| ** **                                                                        | ** ** | **2005**                                   | ** **  | **2004** | ** ** | **2003** | ** ** |
| OIL AND NATURAL GAS REVENUE:                                                      |       |                                       |        |   |   |   |   |
| Oil and natural gas sales                                                         |       | $                                          | 123,450,342 |   | $ | 66,965,411 |   | $ | 38,381,597 |   |
| Loss on hedging and derivatives                                                   |       | (2,267,253                                 | )           | (2,460,063 | ) | (4,455,590 | ) |
| Total revenue                                                                     |       | 121,183,089                                |        | 64,505,348 |   | 33,926,007 |   |
| OPERATING EXPENSES:                                                               |       |                                       |        |   |   |   |   |
| Oil and natural gas operating expenses  including production and ad valorem taxes |       | 17,068,009                                 |        | 9,308,770 |   | 5,115,794 |   |
| Depletion, depreciation, amortization and  accretion                              |       | 40,218,114                                 |        | 21,927,874 |   | 13,577,279 |   |
| General and administrative expenses:                                              |       |                                       |        |   |   |   |   |
| Deferred compensation expense – repriced  options                            |       | 1,627,814                                  |        | 1,135,628 |   | 1,219,349 |   |
| Deferred compensation expense – restricted  stock                            |       | 973,796                                    |        | 498,372 |   | 372,151 |   |
| Bad debt expense                                                                  |       | 65,157                                     |        | — |   | — |   |
| Other general and administrative                                                  |       | 9,769,281                                  |        | 7,812,970 |   | 5,540,140 |   |
| Total operating expenses                                                          |       | 69,722,171                                 |        | 40,683,614 |   | 25,824,713 |   |
| OPERATING INCOME                                                                  |       | 51,460,918                                 |        | 23,821,734 |   | 8,101,294 |   |
| OTHER INCOME (EXPENSE):                                                           |       |                                       |        |   |   |   |   |
| Interest expense, net of amounts  capitalized                                     |       | —                                     |        | (331,399 | ) | (678,805 | ) |
| Amortization of deferred loan costs                                               |       | (152,723                                   | )           | (142,135 | ) | — |   |
| Interest income                                                                   |       | 127,993                                    |        | 36,075 |   | 16,518 |   |
| INCOME BEFORE INCOME TAXES AND CUMULATIVE  EFFECT OF ACCOUNTING CHANGE            |       | 51,436,188                                 |        | 23,384,275 |   | 7,439,007 |   |
| INCOME TAX EXPENSE                                                                |       | (18,077,929                                | )           | (8,255,025 | ) | (2,731,132 | ) |
| INCOME BEFORE CUMULATIVE EFFECT OF  ACCOUNTING CHANGE                             |       | 33,358,259                                 |        | 15,129,250 |   | 4,707,875 |   |
| CUMULATIVE EFFECT OF ACCOUNTING CHANGE                                            |       | —                                     |        | — |   | (357,825 | ) |
| NET INCOME                                                                        |       | $                                          | 33,358,259  |   | $ | 15,129,250 |   | $ | 4,350,050 |   |
|                                                                              |       |                                       |        |   |   |   |   |
| BASIC EARNINGS PER SHARE:                                                         |       |                                       |        |   |   |   |   |
| Income before cumulative effect of  accounting change                             |       | $                                          | 1.95        |   | $ | 1.16 |   | $ | 0.48 |   |
| Cumulative effect of accounting change                                            |       | —                                     |        | — |   | (0.03 | ) |
| Basic earnings per share                                                          |       | $                                          | 1.95        |   | $ | 1.16 |   | $ | 0.45 |   |
| DILUTED EARNINGS PER SHARE:                                                       |       |                                       |        |   |   |   |   |
| Income before cumulative effect of  accounting change                             |       | $                                          | 1.87        |   | $ | 1.11 |   | $ | 0.47 |   |
| Cumulative effect of accounting change                                            |       | —                                     |        | — |   | (0.03 | ) |
| Diluted earnings per share                                                        |       | $                                          | 1.87        |   | $ | 1.11 |   | $ | 0.44 |   |
| BASIC WEIGHTED AVERAGE NUMBER OF COMMON  SHARES OUTSTANDING                       |       | 17,122,121                                 |        | 13,029,075 |   | 9,726,140 |   |
| DILUTED WEIGHTED AVERAGE NUMBER OF COMMON  SHARES OUTSTANDING                     |       | 17,814,701                                 |        | 13,648,261 |   | 9,987,551 |   |

 

See accompanying notes to the consolidated financial statements**.**

 

F-4

----

 

### **EDGE PETROLEUM CORPORATION**

 

**CONSOLIDATEDSTATEMENTS OF COMPREHENSIVE INCOME**

 
| ** **                                                                  | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                  | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| NET INCOME                                                                  |       | $                                          | 33,358,259 |   | $ | 15,129,250 |   | $ | 4,350,050 |   |
| OTHER COMPREHENSIVE INCOME (LOSS), net of  tax:                             |       |                                       |       |   |   |   |   |
| Change in fair value of outstanding hedging  and derivative instruments (1) |       | (3,760,790                                 | )          | 952,556 |   | (2,418,612 | ) |
| Reclassification of hedging and derivative  losses (2)                      |       | 799,435                                    |       | 659,588 |   | 2,896,134 |   |
| Other comprehensive income (loss)                                           |       | (2,961,355                                 | )          | 1,612,144 |   | 477,522 |   |
|                                                                        |       |                                       |       |   |   |   |   |
| COMPREHENSIVE INCOME                                                        |       | $                                          | 30,396,904 |   | $ | 16,741,394 |   | $ | 4,827,572 |   |
|                                                                             |       |                                       |       |   |   |   |   |
| (1) net of income taxes                                                     |       | $                                          | (2,025,041 | ) | $ | 512,915 |   | $ | (1,302,330 | ) |
| (2) net of income taxes                                                     |       | $                                          | 430,465    |   | $ | 355,162 |   | $ | 1,559,456 |   |

 

See accompanying notes to the consolidated financial statements.

 

F-5

----

 

### **EDGE PETROLEUM CORPORATION**

 

**CONSOLIDATEDSTATEMENTS OF CASH FLOWS**

 
| ** **                                                                         | ** ** | **Year Ended December 31,** | ** ** |
|------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                         | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| CASH FLOWS FROM OPERATING ACTIVITIES:                                              |       |                                       |       |   |   |   |   |
| Net income                                                                         |       | $                                          | 33,358,259 |   | $ | 15,129,250 |   | $ | 4,350,050 |   |
| Adjustments to reconcile net income to net  cash provided by operating activities: |       |                                       |       |   |   |   |   |
| Cumulative effect of accounting change                                             |       | —                                     |       | — |   | 357,825 |   |
| Unrealized (gain) loss on the fair value of  derivatives                           |       | (720,413                                   | )          | 564,548 |   | — |   |
| Loss on property                                                                   |       | 1,778                                      |       | — |   | — |   |
| Depletion, depreciation, amortization and  accretion                               |       | 40,218,114                                 |       | 21,927,874 |   | 13,577,279 |   |
| Amortization of deferred loan costs                                                |       | 152,723                                    |       | 142,135 |   | — |   |
| Deferred tax provision                                                             |       | 18,077,929                                 |       | 8,255,025 |   | 2,731,132 |   |
| Non-cash compensation expense                                                      |       | 2,601,610                                  |       | 1,634,000 |   | 1,591,500 |   |
| Bad debt expense                                                                   |       | 65,157                                     |       | — |   | — |   |
| Changes in operating assets and  liabilities:                                      |       |                                       |       |   |   |   |   |
| (Increase) decrease in accounts receivable,  trade                                 |       | (9,770,473                                 | )          | 2,750,033 |   | (3,137,319 | ) |
| (Increase) decrease in accounts receivable,  joint interest owners                 |       | 3,745,781                                  |       | (4,113,196 | ) | (1,187,958 | ) |
| Increase in other assets                                                           |       | (1,061,599                                 | )          | (258,936 | ) | (429,403 | ) |
| Increase (decrease) in accounts payable,  trade                                    |       | 2,051,745                                  |       | 1,408,300 |   | (1,767,685 | ) |
| Increase (decrease) in accrued interest  payable                                   |       | 17,466                                     |       | — |   | (127,698 | ) |
| Increase (decrease) in accrued liabilities                                         |       | 4,372,335                                  |       | (5,168,691 | ) | 7,940,421 |   |
| Net cash provided by operating activities                                          |       | 93,110,412                                 |       | 42,270,342 |   | 23,898,144 |   |
|                                                                               |       |                                       |       |   |   |   |   |
| CASH FLOWS FROM INVESTING ACTIVITIES:                                              |       |                                       |       |   |   |   |   |
| Capital expenditures                                                               |       | (123,958,828                               | )          | (89,470,369 | ) | (33,560,102 | ) |
| Drilling advances                                                                  |       | (4,285,541                                 | )          | — |   | — |   |
| Proceeds from the sale of oil and natural  gas properties                          |       | —                                     |       | 60,000 |   | 330,096 |   |
| Acquisition of Cinco Energy Corporation,  net of cash acquired                     |       | (39,035,176                                | )          | — |   | — |   |
| Cash acquired in merger with Miller  Exploration Company, net of acquisition costs |       | —                                     |       | — |   | 5,159,806 |   |
| Net cash used in investing activities                                              |       | (167,279,545                               | )          | (89,410,369 | ) | (28,070,200 | ) |
|                                                                               |       |                                       |       |   |   |   |   |
| CASH FLOWS FROM FINANCING ACTIVITIES:                                              |       |                                       |       |   |   |   |   |
| Borrowings from long-term debt                                                     |       | 81,000,000                                 |       | 27,000,000 |   | 10,700,000 |   |
| Payments on long-term debt                                                         |       | (16,000,000                                | )          | (28,000,000 | ) | (10,200,000 | ) |
| Net proceeds from issuance of common stock                                         |       | 7,614,937                                  |       | 49,506,784 |   | 2,430,961 |   |
| Deferred loan costs                                                                |       | (46,895                                    | )          | (426,415 | ) | — |   |
| Net cash provided by financing activities                                          |       | 72,568,042                                 |       | 48,080,369 |   | 2,930,961 |   |
|                                                                               |       |                                       |       |   |   |   |   |
| NET INCREASE (DECREASE) IN CASH AND CASH  EQUIVALENTS                              |       | (1,601,091                                 | )          | 940,342 |   | (1,241,095 | ) |
| CASH AND CASH EQUIVALENTS, BEGINNING OF  YEAR                                      |       | 2,267,423                                  |       | 1,327,081 |   | 2,568,176 |   |
| CASH AND CASH EQUIVALENTS, END OF YEAR                                             |       | $                                          | 666,332    |   | $ | 2,267,423 |   | $ | 1,327,081 |   |

 

See accompanying notes to the consolidated financial statements.

 

F-6

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### **EDGE PETROLEUM CORPORATION**

 

### **CONSOLIDATED STATEMENTS OF STOCKHOLDERS’EQUITY**

 
| ** **                                                           | ** ** | **Common Stock** | ** ** | **Additional  Paid-in Capital** | ** ** | **Retained  Earnings** | ** ** | **Accumulated  Other  Comprehensive  Income (Loss)** | ** ** | **Total  Stockholders’  Equity** | ** ** |
|----------------------------------------------------------------------|------------|-----------------------|------------|--------------------------------------|------------|------------------------|------------|-----------------------------------------------------------|------------|---------------------------------------|------------|
| **Shares**                                                           | ** ** | **Amount**            | ** ** |
| ** **                                                           | ** ** | ** **            | ** ** | ** **                           | ** ** | ** **             | ** ** | ** **                                                | ** ** | ** **                            | ** ** | ** ** | ** ** |
| **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                                   |       | —                |       | —                               |       | —                 |       | —                                                    |       | 2,896,134                             |       | 2,896,134 |   |
| Change in valuation of hedging instruments                           |       | —                |       | —                               |       | —                 |       | —                                                    |       | (2,418,612                            | )          | (2,418,612 | ) |
| 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                                   |       | —                |       | —                               |       | —                 |       | —                                                    |       | 659,588                               |       | 659,588 |   |
| Change in valuation of hedging instruments                           |       | —                |       | —                               |       | —                 |       | —                                                    |       | 952,556                               |       | 952,556 |   |
| 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 |   |
| Issuance of common stock                                             |       | 680,875               |       | 6,809                                |       | 7,775,744              |       | —                                                    |       | —                                |       | 7,782,553 |   |
| Deferred compensation expense – restricted  stock               |       | —                |       | —                               |       | 973,796                |       | —                                                    |       | —                                |       | 973,796 |   |
| Deferred compensation expense – repriced  options               |       | —                |       | —                               |       | 1,627,814              |       | —                                                    |       | —                                |       | 1,627,814 |   |
| Tax benefit associated with exercise of  non-qualified stock options |       | —                |       | —                               |       | 507,343                |       | —                                                    |       | —                                |       | 507,343 |   |
| Reclassification of hedging gains                                    |       | —                |       | —                               |       | —                 |       | —                                                    |       | 799,435                               |       | 799,435 |   |
| Change in valuation of hedging instruments                           |       | —                |       | —                               |       | —                 |       | —                                                    |       | (3,760,790                            | )          | (3,760,790 | ) |
| Net income                                                           |       | —                |       | —                               |       | —                 |       | 33,358,259                                                |       | —                                |       | 33,358,259 |   |
| **BALANCE,DECEMBER  31, 2005**                                       | ** ** | 17,216,776            |       | $                                    | 172,168    |                   | $          | 137,841,756                                               |       | $                                     | 55,454,066 |   | $ | (1,712,685 | ) | $ | 191,755,305 |   |

 

See accompanying notes to the consolidated financial statements**.**

 

F-7

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### **EDGE PETROLEUM CORPORATION**

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

**1.****    ****ORGANIZATION AND NATURE OF OPERATIONS**

 

***General******-*** Edge Petroleum Corporation(the “Company”)was organized as a Delaware corporation in August 1996 in connection with itsinitial public offering and the related combination of certain entities thatheld interests in Edge Joint Venture II (the “Joint Venture”) and certain otheroil and natural gas properties; herein referred to as the “Combination”. In aseries of transactions the Company issued an aggregate of 4,701,361 shares ofcommon stock and received in exchange 100% of the ownership interests in theJoint Venture and certain other oil and natural gas properties. In March 1997,and contemporaneously with the Combination, the Company completed the initialpublic offering of 2,760,000 shares of its common stock (the “Offering”). InDecember 2003, the Company completed a merger with Miller Exploration Company (“Miller”)in a stock for stock transaction, in which the Company issued 2.6 millionshares of common stock to the shareholders of Miller. In December 2004 and January2005, the Company completed a public offering of common stock in which 4.0million shares were issued in order to fund the asset acquisition from ContangoOil & Gas Company (“Contango”). In November 2005, the Company acquired 100%of the stock of Cinco Energy Corporation (“Cinco”), which continues as a whollyowned subsidiary named Edge Petroleum Production Company (see Note 6).

 

***Nature of Operations -*****The Company is an independent energy companyengaged in the exploration, development, acquisition and production of oil andnatural gas. The Company’s resources and assets are managed and its results arereported as one operating segment. The Company conducts its operationsprimarily along the onshore United States Gulf Coast, with its primary emphasisin south Texas, Mississippi, Arkansas, Louisiana and Southeast New Mexico. Inits exploration efforts the Company emphasizes an integrated geologicinterpretation method incorporating 3-D seismic technology and advancedvisualization and data analysis techniques utilizing state-of-the-art computerhardware and software.

 

**2.****    ****SUMMARY OF SIGNIFICANT ACCOUNTINGPOLICIES**

 

***Principles of Consolidation******-*** The consolidatedfinancial statements include the accounts of all majority owned subsidiaries ofthe Company, including Edge Petroleum Operating Company Inc., Edge PetroleumExploration Company, Edge Petroleum Production Company (formerly Cinco EnergyCorporation), Miller Oil Corporation, and Miller Exploration Company, which are100% owned subsidiaries of the Company. All intercompany balances andtransactions have been eliminated in consolidation.

 

***Changes in Accounting Principles******–*** None.

 

***Cash and Cash Equivalents -*** The Company considers all highly liquidinvestments with original maturities of three months or less to be cashequivalents.

 

***Financial Instruments -*** The Company’s financial instruments consistof cash, receivables, payables, long-term debt and oil and natural gascommodity hedges. The carrying amount of cash, receivables and payablesapproximates fair value because of the short-term nature of these items. Thecarrying amount of long-term debt as of December 31, 2005 and 2004 approximatesfair value because the interest rates are variable and reflective of marketrates. Our hedging instruments are reflected at fair value based on quotesobtained from our counterparties.

 

***Revenue Recognition -*** The Company recognizesoil and natural gas revenue from its interests in producing wells as oil andnatural gas is produced and sold from those wells. Oil and natural gas sold bythe Company is not significantly different from the Company’s share ofproduction.

 

***Allowance for Doubtful Accounts******-*** The Company routinely assesses the recoverability of all materialtrade and other receivables to determine our ability to collect the receivablesin full. Many of the Company’s receivables are from joint interest owners onproperties of which the Company is the operator. Thus, the Company may have theability to withhold future revenue disbursements to recover any non-payment ofjoint interest billings. Generally, the Company’s crude oil and natural gasreceivables are collected within two to three months. The Company accrues areserve on a receivable when, based on the judgment of management, it isprobable that a receivable will not be collected and the amount of any reservemay be reasonably estimated (see Note 3).

 

F-8

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***Inventories -*******Inventories consist principally of tubular goods and productionequipment, stated at the lower of weighted-average cost or market.

 

***Other Property, Plant & Equipment -***Depreciation of other office furniture andequipment and computer hardware and software is provided using thestraight-line method based on estimated useful lives ranging from three toseven years.

 

***Oil and Natural Gas Properties -***Investments in oil and natural gas properties are accounted for using the fullcost 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. There are several significant differencesbetween these methods. Among these differences is that, under thesuccessful-efforts method, costs such as geological and geophysical (“G&G”),exploratory dry holes and delay rentals are expensed as incurred whereas underthe full-cost method these types of charges are capitalized to their respectivefull-cost pool. In the measurement of impairment of oil and gas properties, thesuccessful-efforts method of accounting follows the guidance provided inStatement of Financial Accounting Standards (“SFAS”) No. 144, *Accounting for the Impairment or Disposal ofLong-Lived Assets*, where the first measurement for impairment is tocompare the net book value of the related asset to its undiscounted future cashflows using commodity prices consistent with management expectations. Thefull-cost method follows guidance provided in Securities and ExchangeCommission (“SEC”) Regulation S-X Rule 4-10, where impairment is determined bycomparing the net book value (full-cost pool) to the future net cash flowsdiscounted at 10% using commodity prices in effect at the end of the reportingperiod.

 

Inaccordance with the full-cost method of accounting, all costs associated withthe exploration, development and acquisition of oil and natural gas properties,including salaries, benefits and other internal costs directly attributable tothese activities are capitalized within a cost center. The Company’s oil andnatural gas properties are located within the United States of America, whichconstitutes one cost center. The Company capitalized $2.6 million, $2.2million, and $1.7 million of general and administrative costs in 2005, 2004 and2003, respectively. The Company also capitalizes a portion of interest expenseon borrowed funds related to unproved oil and gas properties. The Companycapitalized approximately $1.9 million, $0.7 million, and $0.2 million ofinterest costs in 2005, 2004 and 2003, respectively.

 

Oiland natural gas properties are amortized using the unit-of-production methodusing estimates of proved reserve quantities. Investments in unprovedproperties are not amortized until proved reserves associated with theprospects 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 $36.9 million and $15.5 million at December 31, 2005and 2004, 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 Cost Rules,*which the Company adopted in the fourth quarter of 2004 with no impact on theCompany’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 31,2005, 2004 and 2003 were $2.43, $1.78, and $1.59, respectively.

 

Inaddition, the capitalized costs of oil and natural gas properties are subjectto a “ceiling test,” whereby to the extent that such capitalized costs subjectto amortization 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, an impairment of oil and natural gasproperties is not reversible at a later date. In accordance with SAB No. 103, *Update of Codification of Staff Accounting Bulletins*,derivative instruments

 

F-9

----

 

qualifyingas 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, 2005 and thus 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. The period-end price was within the collarestablished by the Company’s hedges at December 31, 2005 and thus did notaffect prices used in this calculation. No adjustment related to the ceilingtest was required during the years ended December 31, 2005, 2004, or 2003.

 

Salesof proved and unproved properties are accounted for as adjustments ofcapitalized costs with no gain or loss recognized, unless such adjustmentswould significantly alter the relationship between capitalized costs and provedreserves.

 

***Asset Retirement Obligations –***The Company accounts for asset retirementobligations under the provisions of SFAS No. 143, *Accounting for Asset Retirement Obligations,*which providesfor an asset and liability approach to accounting for Asset RetirementObligations (“ARO”). Under this method, when legal obligations fordismantlement and abandonment costs, excluding salvage values, are incurred, aliability is recorded at fair value and the carrying amount of the related oiland gas properties is increased. Accretion of the liability is recognized eachperiod using the interest method of allocation and the capitalized cost is depletedover the useful life of the related asset. The Company adopted this policyeffective January 1, 2003, using a cumulative effect approach to recognizetransition amounts for asset retirement obligations, asset retirement costs andaccumulated accretion and depletion. The cumulative effect of the adoption ofSFAS No. 143 and the change in accounting principle was a charge to net incomeduring the first quarter of 2003 of $357,825, net of taxes of $192,675 (seeNote 7).

 

***Income Taxes******-*** The Company accounts for income taxes underthe provisions of SFAS No. 109, *Accountingfor Income Taxes*, which provides for an asset and liability approachto accounting for income taxes. Under this approach, deferred tax assets andliabilities are recognized based on anticipated future tax consequences, usingcurrently enacted tax laws, attributable to differences between financialstatement carrying amounts of assets and liabilities and their respective taxbases (see Note 14).

 

***Stock-Based Compensation -*** The Company accountsfor stock compensation plans under the intrinsic value method of AccountingPrinciples Board (“APB”) Opinion No. 25, *Accountingfor Stock Issued to Employees*. No compensation expense is recognizedfor stock options that had an exercise price equal to the market value of theunderlying common stock on the date of grant. 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 in 2006 (see Recently Issued AccountingPronouncements below).

 

F-10

----

 

Hadcompensation expense for stock-based compensation been determined based on thefair value at the date of grant, our net income and earnings per share wouldhave been as follows:

 
| ** **                                                                                                                           | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                                                           | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| Net income as reported                                                                                                               |       | $                                          | 33,358,259 |   | $ | 15,129,250 |   | $ | 4,350,050 |   |
| Add:                                                                                                                                 |       |                                       |       |   |   |   |   |
| Stock based employee compensation expense  included in reported net income, net of related income tax                                |       | 1,691,047                                  |       | 1,062,100 |   | 771,681 |   |
| Deduct:                                                                                                                              |       |                                       |       |   |   |   |   |
| Total stock based employee compensation  expense determined under fair value based method for all awards, net of  related income tax |       | (748,615                                   | )          | (501,907 | ) | (260,850 | ) |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Pro forma net income                                                                                                                 |       | $                                          | 34,300,691 |   | $ | 15,689,443 |   | $ | 4,860,881 |   |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Earnings Per Share                                                                                                                   |       |                                       |       |   |   |   |   |
| Basic – as reported                                                                                                             |       | $                                          | 1.95       |   | $ | 1.16 |   | $ | 0.45 |   |
| Basic – pro forma                                                                                                               |       | 2.00                                       |       | 1.20 |   | 0.50 |   |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Diluted – as reported                                                                                                           |       | $                                          | 1.87       |   | $ | 1.11 |   | $ | 0.44 |   |
| Diluted – pro forma                                                                                                             |       | 1.93                                       |       | 1.15 |   | 0.49 |   |

 

Nooptions were granted in 2005. The weighted-average fair value of each optiongranted during 2004 and 2003 was $11.03 and $3.24, respectively. The fair valueof each 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% and 73% in 2004 and 2003, respectively; risk freeinterest rate of 3.76% and 3.76% in 2004 and 2003, respectively; averageexpected option lives of ten years for 2004 and eight years in 2003,respectively; and over the vesting period of such options a forfeiture rate of0% for 2004 and 10% for 2003.

 

TheCompany is also subject to reporting requirements of FASB Interpretation No. (“FIN”)44, *Accounting for Certain**Transactions involving Stock Compensation,* that requiresvariable accounting for re-priced stock options. A non-cash charge to deferredcompensation expense is recorded if the market price of the Company’s commonstock at the end of a reporting period is greater than the exercise price ofcertain re-priced stock options. After the first such adjustment is made, eachsubsequent period is adjusted upward or downward to the extent that the marketprice exceeds the exercise price of the options. The charge is related tonon-qualified stock options granted to employees and directors in prior yearsand re-priced in May 1999, as well as certain options newly issued inconjunction with the repricing (see Note 16). A pre-tax charge of $1.6 million,$1.1 million, and $1.2 million was required for the years ended December 31,2005, 2004 and 2003, respectively.

 

***Earnings Per Share -*** The Company accounts for its earnings pershare in accordance with SFAS No. 128, “*Earningsper Share*,” which requires the presentation of “basic” and “diluted”earnings per share (“EPS”) on the face of the income statement. Basic earningsper common share amounts are calculated using the average number of commonshares outstanding during each period. Diluted earnings per share assumes theexercise of all stock options and warrants having exercise prices less than theaverage market price of the common stock using the treasury stock method (seeNote 16).

 

***Derivatives and Hedging Activities -*****The Company adopted SFAS No. 133, *Accounting for Derivative Instruments and HedgingActivities* effective January 1, 2001. The statement, as amended bySFAS No. 137 *Accounting for DerivativeInstruments and Hedging Activities - Deferral of the Effective Date of FASBStatement No. 133 - an Amendment of FASB Statement No. 133*and SFASNo. 138, *Accounting for Certain DerivativeInstruments and Certain Hedging Activities - an Amendment of FASB Statement No.133,*requires that all derivatives be recognized as either assets orliabilities and measured at fair value, and changes in the fair value ofderivatives be reported in current earnings, unless the derivative qualifiesfor special hedge accounting treatment. If

 

F-11

----

 

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 will generallybe reported in Other Comprehensive Income (“OCI”). The gains and losses on thederivative instrument that are reported in OCI will be reclassified to earningsin the period in which earnings are impacted by the hedged item (see Note 9). Uponadoption of SFAS No. 133, the Company recorded a transition adjustment ofapproximately $(1.1) million in accumulated other comprehensive income torecord the fair value of the natural gas hedges that were outstanding at thatdate. If hedge accounting is discontinued because it is probable that aforecasted transaction will not occur, the derivative will continue to becarried on the balance sheet at its fair value and gains and losses that wereaccumulated in other comprehensive income will be recognized in earningsimmediately.

 

***Comprehensive Income -***The Company follows the provisions of SFASNo. 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 on the face of the consolidated statements of comprehensiveincome. For the years ended December 31, 2005, 2004 and 2003, the onlycomponent of other comprehensive income has been changes in fair value ofhedging instruments and reclassifications of hedging gains and losses.

 

***Use of 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. Actualresults could differ from these estimates.

 

Significantestimates include volumes of oil and gas reserves used in calculating depletionof proved oil and natural gas properties, future net revenues and abandonment obligations,impairment of undeveloped properties, future income taxes and relatedassets/liabilities, bad debts, derivatives, contingencies and litigation. Oiland natural gas reserve estimates, which are the basis for unit-of-productiondepletion and the ceiling test, have numerous inherent uncertainties. Theaccuracy of any reserve estimate is a function of the quality of available dataand of engineering and geological interpretation and judgment. Results ofdrilling, testing, and production subsequent to the date of the estimate mayjustify revision of such estimate. Accordingly, reserve estimates are oftendifferent from the quantities of oil and natural gas that are ultimatelyrecovered. In addition, reserve estimates are vulnerable to changes in wellheadprices of crude oil and natural gas. Such prices have been volatile in the pastand can be expected to be volatile in the future.

 

***Concentration of 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 ofcustomers and joint interest owners may impact the Company’s overall creditrisk in that these entities may be similarly affected by changes in economicand other conditions. Historically, the Company has not experienced significantcredit losses on such receivables; however, in 2001, the Company reserved$525,248 related to non-payments from two purchasers of the Company’s oil andnatural gas, which is still in the allowance for doubtful accounts receivableuntil such time as the Company discontinues pursuing recovery efforts. During2005, the Company recorded $65,157 of bad debt expense to increase itsallowance for outstanding receivables from joint interest owners and wrote off$142,386 in accounts receivable from joint interest owners. No bad debt expensewas recorded in 2004 or 2003. The Company cannot ensure that similar suchlosses may not be realized in the future.

 

***Recently Issued Accounting Pronouncements******–*** In December 2004, the FASB issued SFAS No.123(R), *Share-Based Payment.* Thisstatement requires companies to measure the cost of employee services inexchange for an award of equity instruments based on a grant-date fair value ofthe award (with limited exceptions), and that cost must generally be recognizedover the vesting period. SFAS No. 123(R) amends the original SFAS No. 123 and95 that had allowed companies to choose between expensing stock options orshowing pro forma disclosure only. This statement eliminates the ability toaccount for share-based compensation transactions using APB Opinion No. 25. TheCompany currently accounts for stock-based compensation plans under theprinciples prescribed by APB Opinion No. 25. Accordingly, no stock optioncompensation cost is reflected in net income, as all options granted under theplan had an exercise price equal to the market value of the underlying commonstock on the date of grant.

 

F-12

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Theadoption of SFAS No. 123(R) will impact results of operations, but will have noimpact on overall financial position. In March 2005, the SEC issued SAB No.107. Among other things, SAB No. 107 provides interpretive guidance related tothe interaction between SFAS No. 123(R) and certain SEC rules and regulations,as well as provides the SEC staff’s views regarding the valuation ofshare-based payment arrangements for public companies. SFAS No. 123(R) was tobecome effective as of the beginning of the first interim or annual reportingperiod that begins after June 15, 2005, but on April 14, 2005, the SEC issuedpress release 2005-57, which amends the compliance date of SFAS No. 123(R)until fiscal years beginning after June 15, 2005. The Company anticipates adoptingthe provisions of SFAS No. 123(R) in the first quarter of 2006 usingthe modified prospective method for transition. Under this method the Companywill recognize compensation expense for all stock-based awards granted ormodified on or after July 1, 2005, as well as any previously grantedawards 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. The Company expects the impact to be immaterial due tothe fact that it has not issued options since April 2004 and there will only bea minimal amount of unvested options as of our adoption date. SFAS No. 123(R)also requires the benefits of tax deductions in excess of recognizedcompensation cost be reflected as a financing cash flow, rather than as anoperating cash flow as currently required.

 

InDecember 2004, the FASB issued SFAS No. 153, *Exchanges ofNonmonetary Assets, an amendment of APB Opinion No. 29*. SFASNo. 153 is based on the principle that exchanges of nonmonetary assetsshould be measured based on the fair value of the assets exchanged. APB OpinionNo. 29, *Accounting for Nonmonetary Transactions*,provided an exception to its basic measurement principle (fair value) forexchanges of similar productive assets. Under APB Opinion No. 29, anexchange of a productive asset for a similar productive asset was based on therecorded amount of the asset relinquished. SFAS No. 153 eliminates theexception for nonmonetary exchanges of similar productive assets and replacesit with a general exception for exchanges of nonmonetary assets that do nothave commercial substance. Nonmonetary exchange has commercial substance if thefuture cash flows of the entity are expected to change significantly as aresult of the exchange. SFAS No. 153 is effective for fiscal periodsbeginning after June 15, 2005. The adoption of SFAS No. 153 is not expected tohave a material effect on the Company’s consolidated financial position,results of operations or cash flows.

 

InMarch 2005, the FASB issued FASB Interpretation No. 47, *Accounting for Conditional Asset RetirementObligations, an interpretation of FASB Statement No. 143* (“FIN 47”). FIN 47 clarifies that the term, “conditional asset retirement obligation” asused in SFAS No. 143, *Accounting for AssetRetirement Obligations*, refers to a legal obligation to perform anasset retirement activity in which the timing and/or method of settlement are conditionalupon a future event that may or may not be within the control of theentity.  Even though uncertainty about the timing and/or method ofsettlement exists and may be conditional upon a future event, the obligation toperform the asset retirement activity is unconditional.  Accordingly, anentity is required to recognize a liability for the fair value of a conditionalasset retirement obligation if the fair value of the liability can bereasonably estimated.  Uncertainty about the timing and/or method ofsettlement of a conditional asset retirement obligation should be factored intothe measurement of the liability when sufficient information exists.  Thefair value of a liability for the conditional asset retirement obligationshould be recognized when incurred generally upon acquisition, construction, ordevelopment or through the normal operation of the asset.  SFAS No. 143acknowledges that in some cases, sufficient information may not be available toreasonably estimate the fair value of an asset retirement obligation.  FIN47 also clarifies when an entity would have sufficient information toreasonably estimate the fair value of an asset retirement obligation.  FIN47 is effective for fiscal years ending after December 15, 2005. Retrospective application for interim financial information is permitted but isnot required.  The adoption of FIN 47 is not expected to have a materialeffect on the Company’s consolidated financial position, results of operationsor cash flows.

 

InJune 2005, the FASB issued SFAS No. 154, *AccountingChanges and Error Corrections*, *a replacement ofAccounting Principles Board (“APB”) Opinion No. 20 and FASB StatementNo. 3,*which changes the requirements for the accounting forand reporting of a change in accounting principle. It also applies to changesrequired by an accounting pronouncement in the unusual instance that thepronouncement does not include specific transition provisions. Application iseffective for accounting changes and correction of errors made in fiscal yearsbeginning after December 15, 2005. The adoption of SFAS No. 154 is not expectedto have a material effect on the Company’s consolidated financial position,results of operations or cash flows.

 

F-13

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InFebruary 2006, the FASB issued SFAS No. 155, *Accountingfor Certain Hybrid Financial Instruments,*which improves financialreporting by eliminating the exemption from applying SFAS No. 133 to interestsin securitized financial assets so that similar instruments are accounted forsimilarly regardless of the form of the instruments and allows a preparer toelect fair value measurement at acquisition, at issuance, or when a previouslyrecognized financial instrument is subject to a remeasurement (new basis)event, on an instrument-by-instrument basis, in cases in which a derivativewould otherwise have to be bifurcated. Providing a fair value measurementelection also results in more financial instruments being measured at what theFASB regards as the most relevant attribute for financial instruments, fairvalue. SFAS No. 155 is effective for all financial instruments acquired orissued after the beginning of an entity’s first fiscal year that begins afterSeptember 15, 2006. The Company is currently evaluating the impact of thisstandard on its financial position, results of operations and cash flows.

 

***Reclassifications***- Certain reclassifications of prior period balanceshave been made to conform to current reporting practices.

 

**3.****    ****ACCOUNTS RECEIVABLE AND ALLOWANCEFOR DOUBTFUL ACCOUNTS**

 

Below are the components of Accounts Receivable,Joint Interest Owners and Other, as of December 31, 2005 and 2004:

 
| ** **                                                           | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                           | ** ** | **2005**              | ** ** | **2004** | ** ** |
| ** **                                                           | ** ** | ** **            | ** ** | ** ** | ** ** |
| Joint interest owners                                                |       | $                     | 1,212,344  |   | $ | 2,351,749 |   |
| Contango Asset Acquisition Purchase Price  Adjustment (1)            |       | —                |       | 3,366,400 |   |
| Chapman Ranch Field Asset Acquisition  Purchase Price Adjustment (2) |       | 817,610               |       | — |   |
| Other Receivables (3)                                                |       | 75,122                |       | 274,924 |   |
| Allowance for Doubtful Accounts Receivable  (joint interest owners)  |       | (4,771                | )          | (82,000 | ) |
| Net Accounts Receivable, joint interest  owners and other            |       | $                     | 2,100,305  |   | $ | 5,911,073 |   |

 

----

(1)     This amount represents the accrual ofrevenues, net of expenses for the results of operations between November 1,2004 and December 29, 2004 of the acquired properties, pursuant to closingprovisions of the Contango purchase and sale agreement.

 

(2)     This amount represents the accrual ofrevenues, net of expenses for the results of operations between September 1,2005 and October 13, 2005 of the Chapman Ranch Field acquired properties,pursuant to closing provisions of the purchase and sale agreement for theChapman Ranch Field asset acquisition (see Note 6 below).

 

(3)     Other receivables represent variousmiscellaneous refunds or credits that the Company is due that may not relate toJoint Interest Billings or Trade Receivables.

 

Thefollowing table sets forth changes in the Company’s allowance for doubtfulaccounts for the years ended December 31, 2005, 2004 and 2003:

 
| ** **                         | ** ** | **Balance at  Beginning of  Year** | ** ** | **Charged to  Costs and  Expenses** | ** ** | **Deductions  and Other** | ** ** | **Balance at  End of  Year** | ** ** |
|------------------------------------|------------|----------------------------------------------|------------|-----------------------------------------------|------------|--------------------------------|------------|----------------------------------------|------------|
| **Year  ended December 31, 2005:** | ** ** | ** **                                   | ** ** | ** **                                    | ** ** | ** **                     | ** ** | ** **                             | ** ** |
| Allowance for doubtful accounts    |       | $                                            | 607,248    |                                          | $          | 65,157                         |       | $                                      | (142,386   | ) | $ | 530,019 |   |
| **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 |   |

 

F-14

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

 

Below are the componentsof other current assets as of December 31, 2005 and 2004:

 

| ** **                          | ** ** | **December 31,** | ** ** |
|-------------------------------------|------------|-----------------------|------------|
| ** **                          | ** ** | **2005**              | ** ** | **2004** | ** ** |
| ** **                          | ** ** | ** **            | ** ** | ** ** | ** ** |
| Prepaid Insurance                   |       | $                     | 387,906    |   | $ | 426,966 |   |
| Prepayments and Deposits to Vendors |       | 322,945               |       | 498,282 |   |
| Drilling Advances                   |       | 4,285,541             |       | — |   |
| Inventory (1)                       |       | 1,440,301             |       | 520,675 |   |
|                                |       | $                     | 6,436,693  |   | $ | 1,445,923 |   |

 

----

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

 

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

 

AtDecember 31, 2005 and 2004, property and equipment consisted of the following:

 
| ** **                                            | ** ** | **December 31,** | ** **  |
|-------------------------------------------------------|------------|-----------------------|-------------|
| ** **                                            | ** ** | **2005**              | ** **  | **2004** | ** ** |
| Developed oil and natural gas properties              |       | $                     | 401,697,031 |   | $ | 243,187,690 |   |
| Unevaluated oil and natural gas properties            |       | 36,948,399            |        | 15,490,704 |   |
| Computer equipment and software                       |       | 4,490,887             |        | 4,290,905 |   |
| Other office property and equipment                   |       | 2,515,338             |        | 1,990,676 |   |
| Total property and equipment                          |       | 445,651,655           |        | 264,959,975 |   |
| Accumulated depletion, depreciation and  amortization |       | (139,196,140          | )           | (99,119,630 | ) |
| Total property and equipment, net                     |       | $                     | 306,455,515 |   | $ | 165,840,345 |   |

 

Thefollowing table summarizes the cost of the properties not subject toamortization by the year the cost was incurred:

 

| ** **          | ** ** | **December 31,** | ** ** |
|---------------------|------------|-----------------------|------------|
| ** **          | ** ** | **2005**              | ** ** | **2004** | ** ** |
| Year cost incurred: |       |                  |       |   |   |
| 1999                |       | $                     | 193,060    |   | $ | 193,060 |   |
| 2000                |       | —                |       | 8,611 |   |
| 2001                |       | 22,106                |       | 108,448 |   |
| 2002                |       | 88,121                |       | 143,856 |   |
| 2003                |       | 248,002               |       | 1,506,300 |   |
| 2004                |       | 3,510,108             |       | 13,530,429 |   |
| 2005                |       | 32,887,002            |       | — |   |
| Total               |       | $                     | 36,948,399 |   | $ | 15,490,704 |   |

 

**6.****    ****ACQUISITIONS AND DIVESTITURES**

 

**Chapman Ranch Field Acquisitions-**On September 21,2005, the Company executed two separate and definitive agreements for theacquisition of (i) the stock of a private company, Cinco Energy Corporation (“Cinco”),whose primary asset is ownership of working interests in oil and natural gasproperties located on the Chapman Ranch Field in Nueces County, Texas and (ii)additional working interests in the Chapman Ranch Field owned by two otherprivate companies for an aggregate cash purchase price of approximately $62.8million (of which $35.8 million is attributable to the stock purchase and $27.0million is attributable to the working interest asset purchase). The Company allocatedapproximately $17.5 million of the total purchase price to the unprovedproperty category. Both purchase prices were subject to adjustment pursuant tothe provisions of the applicable agreements. The Company also agreed to pay thesellers an aggregate incremental purchase price of $5.2 million (of which $3.0

 

F-15

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million is attributable tothe stock purchase and $2.2 million is attributable to the working interestasset purchase) related to the operator obtaining high-cost gas certificationon or before January 31, 2006, which would provide for severance tax abatementson the properties acquired. The operator of the properties filed for theabatements and the Company was notified recently that not all of the propertiesqualified for high-cost gas certification, therefore the incremental purchaseprice was reduced to $4.8 million in January 2006. On November 30, 2005, theCompany paid a portion of the incremental purchase price of $3.9 million when aportion of the properties qualified for the certification and incurred acontingent liability for the remaining balance of $0.9 million, which was paidto the Sellers in the first quarter of 2006. The Company financed theacquisitions through borrowings under its credit facility, the borrowing baseof which increased in connection with these transactions and other recentactivities since the last redetermination.

 

Theasset purchase closed on October 13, 2005. The cash base purchase price of$27.0 million was adjusted to $28.0 million for the incremental purchase price(see above) and the results of operations between the September 1, 2005effective date and the October 13, 2005 closing date, pursuant to the closingadjustment provisions of the relevant agreement.

 

The stock purchase closed November 30, 2005. The cash base purchaseprice at closing of $35.8 million was subject to adjustment for, among otherthings, working capital as of September 1, 2005 and an incremental purchaseprice (see above), pursuant to the closing provisions of the relevantagreement. The preliminarily adjusted purchase price of Cinco was $47.3million. The following is a calculation of the purchase price paid for Cinco:

 

| **In thousands:**     | ** ** | ** ** | ** ** |
|----------------------------|------------|------------|------------|
| Base purchase price        |       | $          | 35,167     |   |
| Incremental purchase price |       | 2,714      |       |
| Working capital adjustment |       | 8,761      |       |
| Transaction costs          |       | 698        |       |
| Stockholders’ equity  |       | $          | 47,340     |   |

 

The Cinco acquisition was accounted for as a purchase business combination. Under this method of accounting, on the closing date, the assets and liabilities of Cinco were recorded by Edge at their estimated fair market values. The following is the allocation of the purchase price to specific assets and liabilities based on estimates of fair values and costs, which will be adjusted to actual amounts as determined. Such adjustments are not expected to be material.

 

| **In thousands:**      | ** ** | ** ** | ** ** |
|-----------------------------|------------|------------|------------|
| Cash                        |       | $          | 8,305      |   |
| Current assets              |       | 2,470      |       |
| Properties and equipment    |       | 56,363     |       |
| Deferred tax liability (1)  |       | (17,815    | )          |
| Current liabilities         |       | (1,919     | )          |
| Asset retirement obligation |       | (64        | )          |
| Stockholders’ equity   |       | $          | 47,340     |   |

 

----

(1)   Represents certain tax liabilitiesresulting from the fair value and tax basis difference.

 

Cinco was incorporated on October 26, 2004,therefore no results of operations exist prior to that time. The followingunaudited pro forma results for 2004 show the effect on the Company’sconsolidated results of operations as if the Cinco transaction had occurred atinception on October 26, 2004. The following unaudited pro forma results for2005 show the effect on the Company’s consolidated results of operations as ifthe Cinco transaction had occurred on January 1, 2005. The pro forma resultsare the result of combining the statement of income for the Company with thestatement of income for Cinco adjusted for (1) assumption of ARO liabilitiesand accretion expense for the properties acquired, (2) depletion expenseapplied to the adjusted basis of the properties acquired using the purchasemethod of accounting, (3) conversion of Cinco from Successful Efforts method ofaccounting to Full Cost, (4) interest expense on added borrowings necessary tofinance the acquisition and (5) the related income tax effects of theseadjustments based on the applicable statutory rates. The pro forma information isbased upon numerous assumptions, and is not necessarily indicative of futureresults of operations:

 

F-16

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| ** **                   | ** ** | **For the Year-Ended December 31,**           | ** ** |
|------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                   | ** ** | **2005**                                                          | ** ** | **2004** | ** ** |
| ** **                   | ** ** | **(unaudited)**                                                   | ** ** |
| ** **                   | ** ** | **(In thousands, except per share  amounts)** | ** ** |
| Revenue                      |       | $                                                                 | 131,289    |   | $ | 65,007 |   |
| Net income                   |       | $                                                                 | 27,202     |   | $ | 15,069 |   |
| Net income per common share: |       |                                                              |       |   |   |
| Basic                        |       | $                                                                 | 1.59       |   | $ | 1.16 |   |
| Diluted                      |       | $                                                                 | 1.53       |   | $ | 1.10 |   |

 

Pursuantto the terms of the stock purchase agreement, Cinco changed its name to EdgePetroleum Production Company. It will remain a wholly owned subsidiary of theCompany going forward.

 

**Contango Asset Acquisition -**On December 29, 2004, the Company consummated the acquisition ofinterests in oil and natural gas properties located in south Texas fromContango Oil & Gas Company (“Contango”). The final cash purchase price forthe acquisition was $40.1 million, which was adjusted from the original priceof $50.0 million for the results of operations between the July 1, 2004effective date and the December 29, 2004 closing date, pursuant to the closingadjustment provisions. The purchase price was funded from the net proceeds of apublic offering of common stock completed December 21, 2004 (see Note 11).

 

The following unaudited pro forma results for 2004and 2003 show the effect on the Company’s consolidated results of operations asif the Contango Asset Acquisition had occurred on January 1, 2003. They are theresult of combining the statement of income of Edge with the statements ofrevenues and direct operating expenses for the properties adjusted for (i) thecompletion of the public offering of common stock to finance the cash purchaseprice, (ii) assumption of ARO liabilities and accretion expense for theproperties acquired, (iii) depletion, depreciation and amortization expenseapplied to the adjusted basis of the properties acquired using the purchasemethod of accounting and (iv) the related income tax effects of theseadjustments based on the applicable statutory rates. The statements of revenues and directoperating expenses for the Contango Assets exclude all other historicalContango expenses. As a result, certain estimates and judgments were made inpreparing the pro forma adjustments, including as to the incremental expensesassociated with the Contango Assets. Thepro forma information is based upon numerous assumptions, and is notnecessarily indicative of future results of operations:

 

| ** **                   | ** ** | **For the Year-Ended December 31,**           | ** ** |
|------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                   | ** ** | **2004**                                                          | ** ** | **2003** | ** ** |
| ** **                   | ** ** | **(unaudited)**                                                   | ** ** |
| ** **                   | ** ** | **(In thousands, except per share  amounts)** | ** ** |
| Revenue                      |       | $                                                                 | 89,941     |   | $ | 65,173 |   |
| Net income                   |       | $                                                                 | 25,011     |   | $ | 16,370 |   |
| Net income per common share: |       |                                                              |       |   |   |
| Basic                        |       | $                                                                 | 1.47       |   | $ | 1.19 |   |
| Diluted                      |       | $                                                                 | 1.42       |   | $ | 1.17 |   |

 

**Miller Acquisition -**On December 4, 2003, the Company completed its merger with MillerExploration Company (“Miller”). The Company acquired 100% of the outstandingcommon stock of Miller in a stock for stock transaction pursuant to whichMiller became a wholly-owned subsidiary of Edge. Under the terms of the merger

 

F-17

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agreement,each share of issued and outstanding common stock of Miller was converted into1.22342 shares of Edge common stock. Edge issued approximately 2.6 millionshares of Edge common stock to the shareholders of Miller in exchange for allof the outstanding common stock of Miller. The merger was treated as a tax-freereorganization and accounted for as a purchase business combination. Under thismethod of accounting, on the date of the merger, the assets and liabilities ofMiller were recorded by Edge at their estimated fair market values.

 

The following unaudited pro forma results for 2003show the effect on the Company’s consolidated results of operations as if theMiller transaction occurred on January 1, 2002. They are the result ofcombining the statement of income for Edge with the statement of income forMiller adjusted for (i) the revenue and costs associated with certain Alabamaproperties sold by Miller in June of 2003, prior to consummation of the merger,(ii) depletion, depreciation and amortization expense of Miller applied to theadjusted basis of the properties acquired using the purchase method of accounting,and (iii) the related income tax effects of these adjustments based on theapplicable statutory rates. Thepro forma data presented is based on numerous assumptions and is notnecessarily indicative of future results of operations or comparable to actual 2005and 2004 results of the merged companies.

 

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

 

**Divestitures -**During2005, the Company had no divestitures of oil and gas properties. During 2004and 2003, the Company sold oil and gas properties for net proceeds of $60,000and $330,096, respectively. Proceeds from these dispositions were credited tothe full cost pool. The Company’s 2004 asset divestitures related primarily tothe sale of certain oil and gas properties and equipment in Texas, Mississippiand Louisiana. The Company’s 2003 asset divestitures related primarily to thesale of the Company’s interest in affiliated entities, Essex I and II JointVentures, and certain oil and gas properties in Texas and Louisiana.

 

**7.****    ****ASSET RETIREMENT OBLIGATIONS**

 

In June 2001, the FASB issued SFAS No. 143, which requires that anasset retirement obligation (“ARO”) associated with the retirement of atangible long-lived asset be recognized as a liability in the period in whichit is incurred and becomes determinable. Under this method, when liabilitiesfor dismantlement and abandonment costs, excluding salvage values, areinitially recorded, the carrying amount of the related oil and gas propertiesis increased. The fair value of the ARO asset and liability is measured usingexpected future cash outflows discounted at the Company’s credit-adjusted risk-freeinterest rate. Accretion of the liability is recognized each period using theinterest method of allocation, and the capitalized cost is depleted over theuseful life of the related asset.

 

The Company adopted SFAS No. 143 on January 1, 2003, which resulted ina net increase to oil and gas properties of $0.4 million and relatedliabilities of $0.9 million. These amounts reflect the ARO of the Company hadthe provisions of SFAS No. 143 been applied since inception and resulted in anon-cash charge to earnings of $357,825 ($550,500 pre-tax). Going forward theCompany will record an abandonment liability associated with its oil and gaswells when those assets are placed in service. The changes to the ARO duringthe periods ended December 31, 2005 and 2004 are as follows:

 

F-18

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| ** **                      | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------|------------|--------------------------------------------|------------|
| ** **                      | ** ** | **2005**                                   | ** ** | **2004** | ** ** |
| ARO, beginning of year          |       | $                                          | 2,189,088  |   | $ | 1,811,995 |   |
| Additional liabilities incurred |       | 587,972                                    |       | 676,099 |   |
| Liabilities settled             |       | (151,934                                   | )          | (397,974 | ) |
| Accretion expense               |       | 141,120                                    |       | 98,968 |   |
| Revisions                       |       | —                                     |       | — |   |
| ARO, end of year                |       | $                                          | 2,766,246  |   | $ | 2,189,088 |   |
|                            |       |                                       |       |   |   |
| Current portion                 |       | $                                          | 202,469    |   | $ | 193,647 |   |
| Long-term portion               |       | $                                          | 2,563,777  |   | $ | 1,995,441 |   |

 

AROliabilities incurred during the year ended December 31, 2005 includeobligations assumed for 16 wells acquired in the Chapman Ranch Fieldacquisition, as well as obligations for all successful wells drilled during theyear. Liabilities settled during the year ended December 31, 2005 included 20wells that were either plugged or sold.

 

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

 

Below are the componentsof accrued liabilities as of December 31, 2005 and 2004:

 

| ** **                                                   | ** ** | **December 31,** | ** ** |
|--------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                   | ** ** | **2005**              | ** ** | **2004** | ** ** |
| ** **                                                   | ** ** | ** **            | ** ** | ** ** | ** ** |
| Accrued capital expenditures                                 |       | $                     | 9,428,367  |   | $ | 4,653,450 |   |
| Professional services                                        |       | 849,930               |       | 1,021,165 |   |
| Salary and benefits                                          |       | 1,599,617             |       | 1,045,547 |   |
| Royalties payable                                            |       | 4,133,427             |       | 4,451,094 |   |
| Lease operating expenses including ad  valorem taxes payable |       | 1,408,920             |       | 87,620 |   |
| Other                                                        |       | 474,178               |       | 846,818 |   |
| **Total  Accrued Liabilities**                               |       | $                     | 17,894,439 |   | $ | 12,105,694 |   |

 

**9.****             ****HEDGING AND DERIVATIVE ACTIVITIES**

 

Dueto the volatility of oil and natural gas prices, the Company periodicallyenters into price-risk management transactions (e.g., swaps, collars andfloors) for a portion of its oil and natural gas production to achieve a morepredictable cash flow, as well as to reduce exposure from price fluctuations. Whilethe use of these arrangements may limit the Company’s ability to benefit fromincreases in the price of oil and natural gas, it also reduces the Company’spotential exposure to adverse price movements. The Company’s arrangements, tothe extent it enters into any, apply to only a portion of its production,provide only partial price protection against declines in oil and natural gasprices and limit the Company’s potential gains from future increases in prices.None of these instruments are used for trading or speculative purposes. On aquarterly basis, the Company’s management sets all of the Company’s price-riskmanagement policies, including volumes, types of instruments and counterparties.These policies are implemented by management through the execution of trades bythe Chief Financial Officer after consultation and concurrence by the Presidentand Chairman of the Board. The Board of Directors monitors the Company’spolicies and trades.

 

Allof these price-risk management transactions are considered derivativeinstruments and accounted for in accordance with SFAS No. 133, *Accounting for Derivative Instruments and HedgingActivities*. These derivative instruments are intended to hedge ourprice risk and may be considered hedges for economic purposes, but certain of

 

F-19

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thesetransactions may not qualify for cash flow hedge accounting. All derivativeinstrument contracts are recorded on the balance sheet at fair value. For thosederivative instrument contracts that qualify for cash flow hedge accounting,the effective portion of the changes in the fair value of the contracts isrecorded in other comprehensive income and the ineffective portion of thechanges in the fair value of the contracts is recorded in revenue as theyoccur. While the contract is outstanding, the ineffective gain or loss mayincrease or decrease until settlement of the contract depending on the fairvalue at the measurement dates. When the hedged production is sold, therealized gains and losses on the contracts are removed from other comprehensiveincome and recorded in revenue. The Company is currently accounting for itsnatural gas contracts as cash flow hedges of future cash flows from the sale ofnatural gas. For those derivative instrument contracts that either do notqualify for cash flow hedge accounting or the Company does not designate ashedges of future cash flows, the changes in fair value are not deferred throughother comprehensive income, but rather recorded in revenue immediately asunrealized gains or losses. The Company did not apply cash flow hedgeaccounting to its crude oil collars entered into in 2004 and 2005, becausealthough they were economic hedges, they did not qualify for hedge accounting.

 

Forthe years ended December 31, 2005, 2004 and 2003, the Company included inrevenue realized and unrealized losses related to its natural gas hedges andoil derivatives. There was no ineffectiveness recognized during the years endedDecember 31, 2005, 2004 and 2003. The impact on total revenue from hedgingactivities for the three years ended December 31, 2005, 2004 and 2003 was asfollows:

 
| ** **                                                                 | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                 | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| Natural gas hedging contract settlements                                   |       | $                                          | (1,229,900 | ) | $ | (328,500 | ) | $ | (4,455,590 | ) |
| Crude oil derivative contract settlements                                  |       | (1,757,766                                 | )          | (880,765 | ) | — |   |
| Hedge premium reclassification                                             |       | —                                     |       | (686,250 | ) | — |   |
| Mark-to-market reversal of prior period  unrealized change in fair value   |       | 564,548                                    |       | —- |   | — |   |
| Mark-to-market unrealized change in fair  value of oil derivative contract |       | 155,865                                    |       | (564,548 | ) | — |   |
| Loss on hedging and derivatives                                            |       | $                                          | (2,267,253 | ) | $ | (2,460,063 | ) | $ | (4,455,590 | ) |

 

Theoutstanding hedges at December 31, 2005 and 2004 impacting the balance sheetwere 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** | ** **  | **2005**                                                                                                      | ** ** | **2004(4)** | ** ** |
| ***Natural Gas (1):***    |       |                      |       |          |       |       |       |              |         |             |        | $                                                                                                             |       | $ |   |
| 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 |   |
| 08/05                     |       | Natural Gas Collar        |       | 01/01/2006    |       | 12/31/2006 |       | $                 | 7.00-$10.50  |             | 10,000MMbtu |                                                                                                          | (2,497,823 | ) | — |   |
| 08/05                     |       | Natural Gas Collar        |       | 01/01/2006    |       | 12/31/2006 |       | $                 | 7.00-$16.10  |             | 10,000MMbtu |                                                                                                          | (137,077   | ) | — |   |
| ***Crude Oil (2):***      |       |                      |       |          |       |       |       |              |         |             |        |                                                                                                          |       |   |   |
| 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(3)       |       | 01/01/2005    |       | 12/31/2005 |       | $                 | 35.00-$40.00 |             | 200/290Bbl  |                                                                                                          | —     |   | (468,308 | ) |
| 08/05                     |       | Crude Oil Collar          |       | 01/01/2006    |       | 12/31/2006 |       | $                 | 55.00-$80.00 |             | 400Bbl      |                                                                                                          | 155,865    |   | —- |   |
|                      |       |                      |       |          |       |       |       |              |         |             |        | $                                                                                                             | (2,479,035 | ) | $ | 1,356,482 |   |
|                           |            |                           |            |               |            |            |            |                   |              |                  |             |                                                                                                               |            |  |  |  |  |  |

 

F-20

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----

(1)          The Company’s current hedging activities for natural gas were enteredinto on a per MMbtu delivered price basis, using the Houston Ship ChannelIndex, with settlement for each calendar month occurring five business daysfollowing the expiration date.

 

(2)          Hedge accounting is not applied to the Company’s collars on crude oil,which were entered into on a per barrel delivered price basis, using the WestTexas Intermediate Index, with settlement for each calendar month occurringfive business days following the expiration date. The change in fair value isreflected in total revenue during the year.

 

(3)          In August 2004, the Company replaced the contract that was entered intoMay 2004 with a new contract that changes the volume and pricing terms. The putoption is on 200 Bbls/d and the call option is on 290 Bbls/d. This transactionwas completed at no additional cost to the Company.

 

(4)          The fair value of the Company’s outstanding transactions is presented onthe balance sheet by counterparty. The Company’s counterparties net the Company’spositions with them, but the Company cannot present the net of the twocounterparty positions because it does not have legal right of offset.Therefore one counterparty is presented in the Derivative Asset and one ispresented in the Derivative Liability. The crude oil collar with a balance of($468,308) is presented as a liability and the remaining contracts arepresented as an asset. All contracts are considered current.

 

**10.****      ****LONG-TERM DEBT**

 

OnNovember 30, 2005, the Company amended its Third Amended and Restated CreditAgreement (the “Credit Facility”), which it had originally entered into inMarch 2004 (effective December 31, 2003) and previously amended on May 31, 2005.The Credit Facility permits borrowings up to the lesser of (i) the borrowingbase and (ii) $150.0 million. Effective November 30, 2005, the Credit Facility’sborrowing base was increased from $70.0 million to $110.0 million. Theborrowing base under the Credit Facility was increased as a result of theChapman Ranch Field acquisitions and the Company’s drilling activities sincethe last redetermination. The Company’s available borrowing capacity under thisfacility was $25.0 million at December 31, 2005. The Company expects theborrowing base to be redetermined in April 2006 and semiannually thereafter.

 

TheCredit Facility matures December 31, 2007 and is secured by substantially allof the Company’s assets. Borrowings under the Credit Facility bear interest ata rate equal to prime plus 0.50% or LIBOR plus 2.25%. At December 31, 2005 theinterest rate applied to the Company’s outstanding borrowings was 7.5%. As ofDecember 31, 2005, $85.0 million in borrowings were outstanding under theCredit Facility.

 

TheCredit Facility provides for certain restrictions, including but not limitedto, limitations on additional borrowings, sales of oil and natural gasproperties or other collateral, and engaging in merger or consolidationtransactions. The Credit Facility also prohibits dividends and certaindistributions of cash or properties and certain liens. The Credit Facility alsocontains the following financial covenants, among others:

 

•                  The EBITDAX to Interest Expense ratiorequires that the ratio of (a) consolidated EBITDAX (defined as EBITDA plussimilar non-cash items and exploration and abandonment expenses for suchperiod) of the Company for the four fiscal quarters then ended to (b) theconsolidated interest expense of the Company for the four fiscal quarters thenended, not be less than 3.5 to 1.0.

•                  The Working Capital ratio requires that theamount of the Company’s consolidated current assets less its consolidatedcurrent liabilities, as defined in the Credit Facility Agreement, be at least$1.0 million. For the purposes of calculating the Working Capital ratio, thetotal of current assets is adjusted for unused capacity under the CreditFacility Agreement, and derivative financial instruments and the total of currentliabilities is adjusted for derivative financial instruments and assetretirement obligations.

•                  The Maximum Leverage ratio requires that theratio, as of the last day of any fiscal quarter, of (a) Total Indebtedness (asdefined in the Credit Facility Agreement) as of such fiscal quarter to (b) anamount equal to consolidated EBITDAX for the two quarters then ended times two,not be greater than 3.0 to 1.0.

 

ConsolidatedEBITDAX is a component of negotiated covenants with our lenders and ispresented here as part of the Company’s disclosure of its covenant obligations.

 

**11.****      ****SHELF REGISTRATION STATEMENT**

 

Duringthe second quarter 2005, the Company filed a registration statement with theSEC which registered offerings up to $390 million of any combination of debtsecurities, preferred stock, common stock or

 

F-21

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warrantsfor debt securities or equity securities of the Company. Net proceeds, termsand pricing of the offering of securities issued under the shelf registrationstatement will be determined at the time of the offerings. The shelfregistration statement does not provide assurance that the Company will orcould sell any such securities. The Company’s ability to utilize the shelfregistration statement for the purpose of issuing, from time to time, anycombination of debt securities, preferred stock, common stock or warrants willdepend upon, among other things, market conditions and the existence ofinvestors who wish to purchase the Company’s securities at prices acceptable tothe Company. In connection with the filing of the 2005 registration statement,we deregistered the remaining shares then available for sale under our earlier$150 million shelf registration statement filed in 2004.

 

OnDecember 21, 2004, the Company completed an offering of 3.5 million shares ofits common stock, which generated net proceeds of $47.8 million, before directcosts of the offering of $0.6 million. These funds were used to finance thesouth Texas asset acquisition that closed December 29, 2004 and fund other generalcorporate purposes. On January 5, 2005, the underwriters exercised theirover-allotment option for an additional 525,000 shares of common stock, whichgenerated additional net proceeds of $7.2 million. These funds were used toreduce outstanding debt. Each of these sales was made under the Company’sinitial shelf registration statement. At December 31, 2005, the Company had$390 million available for issuance under its 2005 shelf registrationstatement.

 

**12.****      ****COMMITMENTS AND CONTINGENCIES**

 

***Commitments -***At December 31, 2005, the Company wasobligated under non-cancelable operating leases. Following is a schedule of theremaining future minimum lease payments under these leases:

 

| 2006      |   | $         | 817,211   |   |
|-----------|--------|-----------|-----------|--------|
| 2007      |   | 817,211   |      |
| 2008      |   | 826,227   |      |
| 2009      |   | 817,850   |      |
| 2010      |   | 816,074   |      |
| 2011      |   | 803,642   |      |
| Remainder |   | 1,272,434 |      |
| Total     |   | $         | 6,170,649 |   |

 

Rentexpense for the years ended December 31, 2005, 2004 and 2003 was approximately $655,500,$474,300, and $442,700, respectively.

 

***Contingencies -***  Fromtime to time the Company is a party to various legal proceedings arising in theordinary course of business. While the outcome of lawsuits cannot be predictedwith certainty, the Company is not currently a party to any proceeding that itbelieves, if determined in a manner adverse to the Company, could have amaterial adverse effect on the Company’s financial condition, results ofoperations or cash flows except as set forth below.

 

**Texas Comptroller Audit** - During the second quarter of 2004, theCompany received notice that its franchise tax returns for the State of Texaswould be audited for the tax years 1999 through 2002. After reviewing documentssubmitted, the agent representing the Office of the Comptroller of the State ofTexas proposed adjustments to the calculation that would result in an increasedfranchise tax liability. The agent maintained that transfers by the Company toits subsidiaries that the Company classified as intercompany loans shouldinstead be classified as equity investments in the subsidiary. The State ofTexas originally proposed that the franchise tax liability of the subsidiarieswould be increased by approximately $3.0 million for the four-year period underaudit.

 

During the third quarter of2004, the agent reduced the proposed franchise tax deficiency adjustment to theCompany and its subsidiaries to an aggregate of $467,000. In the fourth quarterof 2004, there was an informal hearing at the local Comptroller’s Office duringwhich the agent indicated he would formally assess the proposed deficiency. OnMarch 24, 2005, the Company received such deficiency assessment in the amountof $471,482 including penalty and interest. The Company responded on April 21,2005 with a request for a formal redetermination hearing. On February 14, 2006,a Hearings Attorney for the Texas Comptroller of Public Accounts

 

F-22

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issued a Position Letterreaffirming the auditor’s assessment, and rejecting the Company’s arguments asset forth in its April 21, 2005, request for redetermination. On February 24,2006, the Company filed a motion to set the matter for oral hearing before anAdministrative Law Judge. Prior to the oral hearing the Company will submitadditional written materials to the Hearings Attorney. The Company intends tocontinue to vigorously contest the assessment through appropriateadministrative levels in the Comptroller’s Office and any other available means.Due to its intention to continue to vigorously contest the proposedadjustments, the Company has not recognized any provision for the additionalfranchise taxes that would result from the proposed deficiency.

 

**Wade and Joyce Montet, et al., v. Edge Petroleum Corpof Texas, et al., consolidated with Rolland L. Broussard, et al., v. EdgePetroleum Corp of Texas, et al.**-**Thisis a consolidated suit, filed in state court in Vermilion Parish, Louisiana inSeptember 2003 by two groups of plaintiffs against Anadarko E&P Company,Norcen Explorer, Inc., Union Pacific Resources Company, Pan Canadian PetroleumCorporation, Japex (U.S.) Corporation, Vale Energy Corporation, Devon LouisianaCorporation and Edge Petroleum Exploration Company (a wholly owned subsidiaryof the Company). Plaintiffs are mineral/royalty owners under theNorcen-Broussard No. 1 and 2 wells, Marg Tex Reservoir C, Sand Unit A (hereinthe “MT RC SUA”, our Bayou Vermilion Prospect). They claim the operator at thetime, Norcen Explorer, now Anadarko, failed to “block squeeze” the sections ofthe No. 2 well, as would a prudent operator, to protect the gas reservoir frombeing flooded with water from adjacent underground formations. Plaintiffsfurther allege Norcen was negligent in not creating a field-wide unit toprotect their interests. Plaintiffs have named the Company and other workinginterest owners in the leases as defendants, including Norcen Explorer’ssuccessors in interest, Anadarko. Plaintiffs seek unspecified damages for lostroyalties and damages due to alleged devaluation of their mineral and propertyinterests, plus interest and attorneys’ fees. In early 2005, the Company fileda motion for summary judgment in the case asserting, among other defenses,that:  (i) there has been no breach ofcontract, (ii) there is no express or implied duty imposed on the Company toblock squeeze the well or form a field-wide unit, (iii) the units were properlyformed by the Conservation Commissioner in accordance with the statutory schemein Louisiana, and (iv) plaintiffs’ claims are barred by limitations, and (v) otherdefenses. The Company and other defendants also filed a special preemptorychallenge of no cause of action under the leases and the Louisiana Mineral Codefor failure to exhaust administrative remedies and due to lack of a demand. InMay and June, 2005, the court ruled against the motion for summary judgment andthe preemptory challenges. Of the 18.75% after-payout working interest that theCompany originally reserved in the leases, the Company owned 2.8% workinginterest at the time of the alleged acts or omissions. On September 6, 2005, theCompany was granted leave by the court to file a third party demand to join theother working interest owners who hold the remainder of the 18.75% workinginterest as direct defendants in this case, and those pleadings have beenserved on the parties.

 

Asof the date of this report, it is not possible to determine what, if any, theCompany’s exposure might be in this matter. The plaintiffs’ expert witness, inhis December 2005 deposition, offered his theory that plaintiffs’ gross damagesare in the range of $19 to 20 million. That number is based on his theory thatthe alleged failure to block squeeze the well resulted in the under-productionof gas worth $300 million. Plaintiffs’ royalty share of that figure yields the$19 to $22 million range of alleged damages. Based on the expert’s testimony,damages attributable to the full 18.75% interest would be in the range of $3.75million gross or $560,000 net to the Company’s 2.8% share would be in the rangeof $560,000 (excluding interest and attorneys’ fees). The Company and otherdefendants have hired their own expert witnesses who have refuted these claims,particularly the expert’s assertions that failure to block squeeze the wellcaused any damages to the reservoir. There is currently a trial setting in thecase of May 22, 2006.

 

The Company may haveinsurance coverage for all or part of this claim up to the $2.0 million limitof the policy. A claim was submitted to the Company’s casualty carrier, who iscurrently providing a defense under a reservation of rights letter. The Companybelieves that it would only be liablefor its 2.8% share of any damage award unless a co-party defendant cannotsatisfy its share of any final judgment. The Company intends to continueto vigorously contest this suit. The Company has not established any reserve withrespect to these claims.

 

**13.****      ****SALES TO MAJOR CUSTOMERS ANDOPERATORS**

 

Inaccordance with Statement of Financial Accounting Standards No. 131 (“SFAS No.131”), *Disclosures about Segments of anEnterprise and Related Information*, public business enterprises arerequired to report financial and

 

F-23

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otherinformation about operating segments of the entity for which such informationis available and is utilized by the chief operating decision maker. SFAS No.131 also establishes standards for related disclosures about products andservices, geographic area, and major customers. The Company operates as onebusiness segment. We sold natural gas and crude oil production representing 10%or more of our total revenues for the years ended December 31, 2005, 2004, and 2003as listed below:

 

| ** **                   | ** ** | **For the year ended December 31,** | ** ** |
|------------------------------|------------|--------------------------------------------------------------|------------|
| **Purchaser**                | ** ** | **2005**                                                     | ** ** | **2004** | ** ** | **2003** | ** ** |
| Kinder Morgan                |       | 29%                                                          |       | * |   | * |   |
| ChevronTexaco                |       | 18%                                                          |       | 22% |   | 6% |   |
| Copano Field Services        |       | 17%                                                          |       | 19% |   | 16% |   |
| Upstream Energy Services (1) |       | 5%                                                           |       | 22% |   | 38% |   |
| BTA                          |       | *                                                            |       | 2% |   | 18% |   |

 

----

| * Zero or less than 1%                                                                                 |
|--------------------------------------------------------------------------------------------------------|
| (1) Upstream Energy Services is an agent that sells our production to  other purchasers on our behalf. |

 

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

 

Inthe exploration, development and production business, production is normallysold to relatively few customers. A significant portion of our sales are madeon our behalf by the operators of the properties and therefore these entitiesmay be listed above. Substantially all of the Company’s customers areconcentrated in the oil and gas industry and revenue can be materially affectedby current economic conditions and the price of certain commodities such asnatural gas and crude oil, the cost of which is passed through to the customer.However, based on the current demand for natural gas and crude oil and the factthat alternate purchasers are readily available, we believe that the loss ofany of our major purchasers would not have a long-term material adverse effecton 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. Under thismethod, future income tax assets and liabilities are determined based on the “temporarydifferences” between the accounting basis and the income tax basis of theCompany’s assets and liabilities measured using the currently enacted, orsubstantially enacted, income tax rates in effect when these differences areexpected to reverse. Significant components of the Company’s deferred taxliabilities and assets as of December 31, 2005 and 2004 are as follows:

 

| ** **                                                           | ** ** | **December 31,** | ** **  |
|----------------------------------------------------------------------|------------|-----------------------|-------------|
| ** **                                                           | ** ** | **2005**              | ** **  | **2004** | ** ** |
| Deferred tax liability:                                              |       |                  |        |   |   |
| Book basis of oil and natural gas properties  in excess of tax basis |       | $                     | (58,246,491 | ) | $ | (28,874,455 | ) |
| Deferred tax assets:                                                 |       |                  |        |   |   |
| Net operating loss carryforwards                                     |       | 19,531,797            |        | 25,857,283 |   |
| Expenses not currently deductible for tax  purposes                  |       | 542,500               |        | 350,000 |   |
| Accretion on ARO                                                     |       | 179,955               |        | 130,563 |   |
| Deferred compensation                                                |       | 1,076,226             |        | 572,304 |   |
| Federal alternative minimum tax credits                              |       | 445,300               |        | 75,000 |   |
| Price risk management liability                                      |       | 670,070               |        | (474,766 | ) |
| Other                                                                |       | 421,543               |        | 405,360 |   |
| Total deferred tax asset                                             |       | 22,867,391            |        | 26,915,744 |   |
| Net deferred tax asset (liability)                                   |       | $                     | (35,379,100 | ) | $ | (1,958,711 | ) |

 

F-24

----

 

InNovember 2005, the Company recorded a deferred tax liability of $17.8 millionassociated with the Cinco acquisition. Tax benefits of $507,343, $462,020 and$137,141 for the years ended December 31, 2005, 2004, and 2003, respectively,are reflected as a component of equity. These tax benefits relate to theexercise of qualified stock options and the vesting of restricted stock atprices higher than those used for financial reporting purposes. Upon adoptionof SFAS No. 143 on January 1, 2003, the Company recorded a cumulative effect ofchange in accounting principle of $357,825, after taxes of $192,675.

 

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

 

| ** ** | ** ** | **2005**   | ** ** | **2004**  | ** ** | **2003**  | ** ** |
|------------|------------|------------|------------|-----------|------------|-----------|------------|
| Current    |       | $          | 327,400    |      | $          | —    |       | $ | — |   |
| Deferred   |       | 17,750,529 |       | 8,255,025 |       | 2,731,132 |       |
| Total      |       | $          | 18,077,929 |      | $          | 8,255,025 |       | $ | 2,731,132 |   |

 

Thedifferences between the statutory federal income taxes calculated using afederal tax rate of 35% and the Company’s effective tax rate is summarized asfollows:

 

| ** **                                          | ** ** | **2005** | ** ** | **2004** | ** ** | **2003**  | ** ** |
|-----------------------------------------------------|------------|----------|------------|----------|------------|-----------|------------|
|                                                |       |     |       |     |       |      |       |   |   |   |
| Statutory federal income taxes                      |       | $        | 18,002,666 |     | $          | 8,184,496 |       | $ | 2,603,653 |   |
| Expenses not deductible for tax purposes  and other |       | 75,263   |       | 70,529   |       | 127,479   |       |
| Income tax expense                                  |       | $        | 18,077,929 |     | $          | 8,255,025 |       | $ | 2,731,132 |   |

 

AtDecember 31, 2005, the Company had cumulative net operating loss carryforwards(“NOLs”) for federal income tax purposes of approximately $55.8 million thatexpire beginning 2020 through 2024. The Company believes that it is more likelythan not that it will utilize all of these NOLs in connection with federalincome taxes generated in the future. The estimated NOLs presented hereinassume that certain items, primarily intangible drilling costs, have beenwritten off for tax purposes in the current year. However, the Company has notmade a final determination if an election will be made to capitalize all orpart of these items for tax purposes in the future.

 

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

 

***Effective July 1, 1997, the Companyestablished a defined-contribution 401(k) Savings & Profit Sharing PlanTrust (the “Plan”) covering employees of the Company who are age 21 or older. TheCompany’s matching contributions to the Plan are discretionary. For the yearsended December 31, 2005, 2004 and 2003, the Company contributed approximately $176,500,$121,300, and $74,200, respectively, to the Plan.***

*** ***

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

 

***Private Offering –*** In connection with a private offering on May6, 1999 of 1,400,000 shares of common stock at a price of $5.40 per share theCompany issued warrants for $0.125 per warrant, to acquire an additional420,000 shares of common stock at $5.35 per share and were exercisable through May6, 2004. All of these warrants have now been exercised. At the election of theCompany, the warrants could have been called at a redemption price of $0.01 perwarrant at any time after any date at which the average daily per share closingbid price for the immediately preceding 20 consecutive 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 Chairmanand Chief Executive Officer, exercised the remaining warrants, which resultedin the Company’s issuance to him of 45,000 shares of common stock and netproceeds to us of $240,750.

 

F-25

----

 

***Public Offering***- In connection with a public offering on December 21, 2004, the Company issued3,500,000 shares of common stock at a gross price of $14.45 per share. Thisoffering generated net proceeds to us, after underwriter’s fees and beforedirect costs of the offering, of $47.8 million. These shares were issued togenerate funds to finance the Contango Asset Acquisition that was completedDecember 29, 2004. In January 2005, the underwriters exercised theiroverallotment option for 525,000 additional shares of common stock, resultingin an additional $7.2 million of net proceeds to the Company.

 

***Stock Plans -*** In conjunction with the Offering, theCompany established the Incentive Plan of Edge Petroleum Corporation (the “IncentivePlan”). The Incentive Plan is discretionary and provides for the granting ofawards, including options for the purchase of the Company’s common stock andfor the issuance of restricted and/or unrestricted common stock to directors,officers, employees and independent contractors of the Company. The options andrestricted stock granted to date vest over periods of 2-3 years. The Companyamended the Incentive Plan in December 2003, to increase the shares availableunder the plan from 1.2 million to 1.7 million. An aggregate of 1,700,000shares of common stock have been reserved for grants under the Incentive Plan,of which 355,224 shares were available for future grants at December 31, 2005.The following nonqualified stock option awards and restricted stock grants weremade under the Incentive Plan during each of the years indicated below:

 

| ** **                     | ** ** | **Number  Granted** | ** ** | **Market Value on  Date of Grant** | ** ** |
|--------------------------------|------------|---------------------|------------|--------------------------------------------------------|------------|
| ***Options Awards:***          |       |                |       |                                                   |       |
| 2005                           |       | —              |       | —                                                 |       |
| 2004                           |       | 13,000              |       | $13.99                                                 |       |
| 2003                           |       | 32,000              |       | $3.88 to $5.73                                         |       |
|                           |       |                |       |                                                   |       |
| ***Restricted Stock Awards:*** |       |                |       |                                                   |       |
| 2005                           |       | 131,640             |       | $14.02 to $25.12                                       |       |
| 2004                           |       | 94,676              |       | $10.09 to $16.89                                       |       |
| 2003                           |       | 91,400              |       | $3.88 to $6.80                                         |       |

 

Stockoption awards issued to date vest 100% two years from date of grant. For awardsissued to date, shares of common stock associated with the restricted stockawards will be issued, subject to continued employment, ratably over threeyears in accordance with the award’s vesting schedule, beginning on the firstanniversary of the date of grant. Compensation expense from restricted stock isamortized over the vesting period and offset to additional paid in capital.Below is a summary of amortization of deferred compensation related torestricted stock awards for the years indicated:

 

| **Year Ended   December 31,** | ** ** | **Deferred  Compensation  Expense** | ** ** |
|----------------------------------------------|------------|-------------------------------------|------------|
| 2005                                         |       | $                                   | 973,796    |   |
| 2004                                         |       | 498,372                             |       |
| 2003                                         |       | 372,151                             |       |
|                                              |            |                                     |            |  |

 

EffectiveMay 21, 1999, the Company amended and restated the Incentive Plan. Inconjunction with those and other****amendments ofthe Incentive Plan, the Company exchanged, on a voluntary basis, 556,488outstanding nonqualified stock options of certain employees and Directors of theCompany for 326,700 new common stock options in replacement 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 aten-year term with 50% of the options vesting immediately on the date of grantwith the remaining 50% vesting on May 21, 2000. On May 21, 1999, in conjunctionwith the repricing, the Company also issued 99,800 new ten-year common stockoptions to employees, which vested 100% on May 21, 2001. The exercise price ofthe new options was $7.06, which represents the fair market value on the dateof grant. On June 1, 1999, the Company issued 21,000 ten-year common stockoptions to non-employee directors with an exercise price of $7.28 per share,which represented their fair market value at the date of grant, vesting 100% onJune 1, 2001.

 

F-26

----

 

Deferredcompensation cost reported in accordance with FIN 44 (see Note 2 above) included a charge for the year endedDecember 31, 2005. Below is a summary of FIN 44 charges related to the variableaccounting for certain re-priced stock options impacting the Company’sstatement of operations for the years indicated:

 

| **Year Ended   December 31,** | ** ** | **Charge** | ** ** |
|----------------------------------------------|------------|------------|------------|
| 2005                                         |       | $          | 1,627,814  |   |
| 2004                                         |       | 1,135,628  |       |
| 2003                                         |       | 1,219,349  |       |
|                                              |            |            |            |  |

 

Asa component of his employment agreement with the Company, John Elias, CEO andChairman of the Board, has been granted option awards and a restricted stockaward outside of the Incentive Plan. Mr. Elias has also been granted someoptions and restricted stock under the Incentive Plan. The options vest andbecome exercisable over a two or three year period subsequent to issue. Therestricted stock is issued ratably over three years in accordance with theaward’s vesting schedule, beginning on the first anniversary of the date ofgrant. Compensation expense is amortized over the vesting period and offset toadditional paid in capital. The amortization of compensation expense related tothis award was included in the amounts discussed above. Below is a summary ofoption and restricted stock grants to Mr. Elias made outside of the IncentivePlan:

 
| **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)          Valuewas $7.75 per share, the market value on the date of grant.

 

F-27

----

 

Asummary of the status of the Company’s stock options and changes as of and foreach of the three years ended December 31, 2005 is presented below:

 
| ** **                                                        | ** ** | **2005**   | ** ** | **2004**                               | ** ** | **2003**   | ** ** |
|-------------------------------------------------------------------|------------|------------|------------|----------------------------------------|------------|------------|------------|
| ** **                                                        | ** ** | **Shares** | ** ** | **Weighted  Average  Exercise  Price** | ** ** | **Shares** | ** ** | **Weighted  Average  Exercise  Price** | ** ** | **Shares** | ** ** | **Weighted  Average  Exercise  Price** | ** ** |
| Outstanding, January 1                                  |       | 822,050    |       | $                                      |  5.91 |       | 1,171,512  |   | $ | 8.76 |   | 1,098,050 |   | $ |  5.62 |   |
| Granted                                                           |       | —     |       | —                                 |       | 50,000     |       | $ | 13.99 |   | 82,000 |   | $ | 4.35 |   |
| Assumed in merger                                                 |       | —     |       | —                                 |       | —     |       | — |   | 120,138 |   | $ | 39.76 |   |
| Forfeited                                                         |       | —     |       | —                                 | ** ** | (76,739    | )          | $ | 59.11 |   | (24,000 | ) | $ | 6.04 |   |
| Exercised                                                         |       | (86,600    | )          | $                                      | 5.67       | ** ** | (322,723   | ) | $ | 6.24 |   | (104,676 | ) | $ | 4.07 |   |
| Outstanding, December 31                                          |       | 735,450    |       | $                                      | 5.93       | ** ** | 822,050    | ** ** | $ | 5.91 |   | 1,171,512 |   | $ | 9.14 |   |
| Exercisable, December 31                                          |       | 685,450    |       | $                                      | 5.35       | ** ** | 690,050    | ** ** | $ | 5.51 |   | 843,412 |   | $ | 10.67 |   |
|                                                              |       |       |       |                                   |       |       |       |   |   |   |   |   |   |
| Weighted average fair value of options  granted during the period |       | *****      | ** ** |                                   |       | $          | 13.99      |   |   |   | $ | 3.23 |   |   |   |
|                                                                   |            |            |            |                                        |            |            |            |  |  |  |  |  |  |  |  |  |  |  |

 

----

*No options were granted in 2005.

 

Asummary of the Company’s stock options categorized by class of grant atDecember 31, 2005 is presented below:

 
| **All Options**               | ** **   | **Options Exercisable** | ** ** |
|------------------------------------|--------------|------------------------------|------------|
| **Range of  Exercise  Price** | ** **   | **Options  Outstanding**     | ** ** | **Weighted  Average  Remaining  Contractual  Life** | ** ** | **Weighted  Average  Exercise  Price** | ** ** | **Range of  Exercise  Price** | ** ** | **Options  Outstanding** | ** ** | **Weighted  Average  Exercise  Price** | ** ** |
| $                                  | 3.00 - $3.88 |                         | 122,500    |   | 5.56 |   | $ | 3.51 |   | $3.00-$3.88 |   | 122,500 |   | $ | 3.51 |   |
| $                                  | 4.22         |                         | 200,000    |   | 3.01 |   | $ | 4.22 |   | $4.22 |   | 200,000 |   | $ | 4.22 |   |
| $                                  | 5.18 - $5.73 |                         | 169,500    |   | 6.30 |   | $ | 5.47 |   | $5.18-$5.73 |   | 169,500 |   | $ | 5.47 |   |
| $                                  | 7.06 - $7.58 |                         | 143,350    |   | 3.62 |   | $ | 7.11 |   | $7.06-$7.58 |   | 143,350 |   | $ | 7.11 |   |
| $                                  | 8.88         |                         | 50,000     |   | 5.01 |   | $ | 8.88 |   | $8.88 |   | 50,000 |   | $ | 8.88 |   |
| $                                  | 13.50-$13.99 |                         | 50,100     |   | 8.24 |   | $ | 13.99 |   | $13.50 |   | 100 |   | $ | 13.50 |   |

 

***Computation of Earnings per Share -***Thefollowing is presented as a reconciliation of the numerators and denominatorsof basic and diluted earnings per share computations, in accordance with SFASNo. 128.

 

| ** **                              | ** ** | **Year Ended December 31, 2005** | ** ** |
|-----------------------------------------|------------|------------------------------------------------------|------------|
| ** **                              | ** ** | **Income  (Numerator)**                              | ** ** | **Shares  (Denominator)** | ** ** | **Per Share  Amount** | ** ** |
| **Basic  EPS**                          |       |                                                 |       |   |   |   |   |
| Income available to common stockholders |       | $                                                    | 33,358,259 |   | 17,122,121 |   | $ | 1.95 |   |
| **Effect  of Dilutive Securities**      |       |                                                 |       |   |   |   |   |
| Common stock options                    |       | —                                               |       | 497,645 |   | (0.06 | ) |
| Restricted stock                        |       | —                                               |       | 194,935 |   | (0.02 | ) |
| **Diluted  EPS**                        |       |                                                 |       |   |   |   |   |
| Income available to common stockholders |       | $                                                    | 33,358,259 |   | 17,814,701 |   | $ | 1.87 |   |

 

F-28

----

 

| ** **                              | ** ** | **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 |   |

 

Associatedwith the exercise of stock options, the Company received a tax benefit of $507,343,$462,020 and $137,141 in 2005, 2004 and 2003, respectively. The tax benefit isrecorded as an increase in additional paid-in capital.

 

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

 

The transactions described below were withaffiliates, and it is possible that the Company would have obtained differentterms from a truly unaffiliated 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 in excess of 0.075% in any one well or prospect.Essex I Joint Venture and Essex II Joint Venture (a joint venture of which Mr.Sfondrini and a company wholly owned by him are the managers) own royalty andoverriding royalty interests in various wells operated by the Company. Thecombined royalty and overriding royalty interests of the Essex I and Essex IIJoint Ventures do not exceed 6.2% in any one well or prospect. The grossamounts paid or accrued to these persons and entities by the Company in 2005 (includingnet revenue, royalty and overriding royalty interests) and the amounts thesesame persons and entities paid to the Company for their respective share oflease operating expenses and other costs is set forth in the following table:

 

F-29

----

 

| **Owner**                              | ** ** | **Total Amounts  Paid by the  Company to  Owners in  2005 including  Overriding  Royalty (1)** | ** ** | **Lease  Operating  Expenses  paid to the  Company by  Owners in  2005** | ** ** |
|----------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------|------------|
| Andex Corporation /Texedge Corporation |       | $                                                                                                                                 | 2,516      |                                                                                         | $          | — |   |
| Bamaedge, L.P.                         |       | 2,057                                                                                                                             |       | —                                                                                       |       |
| Edge Group Partnership                 |       | 291,773                                                                                                                           |       | 66,146                                                                                       |       |
| Edge Holding Co., L.P.                 |       | 54,048                                                                                                                            |       | 12,711                                                                                       |       |
| Essex I Royalty Joint Venture          |       | 23,887                                                                                                                            |       | —                                                                                       |       |
| Essex II Royalty Joint Venture         |       | 79,781                                                                                                                            |       | 13,114                                                                                       |       |
| Jovin, L.P.                            |       | —                                                                                                                            |       | —                                                                                       |       |
| Stanley Raphael                        |       | 3,630                                                                                                                             |       | 659                                                                                          |       |
| **Total**                              |       | $                                                                                                                                 | 457,692    |                                                                                         | $          | 92,630 |   |

 

----

(1)          In the case of Essex I and II Royalty JointVentures, amount includes royalty income in addition to working interest andoverriding royalty income. The Company sold its interest in these entities in2003, but Mr. Sfondrini, a Director, maintains an indirect interest in theseentities.

 

**18.****      ****SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES**

 

Asummary of non-cash investing and financing activities for the years endedDecember 31, 2005, 2004 and 2003 is presented below:

 

| **Description**                                                                                      | ** ** | **Number  of shares  issued** | ** ** | **Fair Market  Value** | ** ** |
|------------------------------------------------------------------------------------------------------|------------|------------------------------------|------------|-----------------------------|------------|
| **2005:**                                                                                            |       |                               |       |                        |       |
| Shares issued to satisfy restricted stock  grants                                                    |       | 59,295                             |       | $                           | 569,724    |   |
| Shares issued to fund the Company’s  matching contribution under the Company’s 401(k) plan |       | 9,980                              |       | $                           | 167,616    |   |
| **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 |   |

 

SupplementalDisclosure of Cash Flow Information

 
| ** **                               | ** ** | **For the Year Ended December 31,** | ** ** |
|------------------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                               | ** ** | **2005**                                                     | ** ** | **2004** | ** ** | **2003** | ** ** |
| Cash paid during the period for:         |       |                                                         |       |   |   |   |   |
| Interest, net of amounts capitalized     |       | $                                                            | —     |   | $ | 331,399 |   | $ | 678,805 |   |
| Federal alternative minimum tax payments |       | 327,400                                                      |       | — |   | — |   |
|                                          |            |                                                              |            |  |  |  |  |  |  |  |

 

F-30

----

 

**19.****      ****SUPPLEMENTAL FINANCIAL QUARTERLY RESULTS (unaudited):**

 

The sum of the individualquarterly basic and diluted earnings (loss) per share amounts may not agreewith year-to-date basic and diluted earnings (loss) per share amounts as aresult of each period’s computation being based on the weighted average numberof common shares outstanding during that period.

 
| ** **                  | ** ** | **Fourth  Quarter**                                                   | ** ** | **Third  Quarter** | ** ** | **Second  Quarter** | ** ** | **First  Quarter** | ** ** |
|-----------------------------|------------|-----------------------------------------------------------------------|------------|--------------------|------------|---------------------|------------|--------------------|------------|
| ** **                  | ** ** | **(in thousands, except per share amounts)** | ** ** |
| **2005:**                   |       |                                                                  |       |               |       |                |       |               |       |
| Oil and natural gas revenue |       | $                                                                     | 42,444     |               | $          | 29,585              |       | $                  | 26,210     |   | $ | 22,944 |   |
| Operating expenses          |       | (21,943                                                               | )          | (17,083            | )          | (15,056             | )          | (15,640            | )          |
| Operating income            |       | 20,501                                                                |       | 12,502             |       | 11,154              |       | 7,304              |       |
| Other expense, net          |       | (3                                                                    | )          | (8                 | )          | (11                 | )          | (3                 | )          |
| Income tax expense          |       | (7,216                                                                | )          | (4,351             | )          | (3,934              | )          | (2,577             | )          |
| Net income                  |       | $                                                                     | 13,282     |               | $          | 8,143               |       | $                  | 7,209      |   | $ | 4,724 |   |
| Basic earnings per share    |       | $                                                                     | 0.78       |               | $          | 0.47                |       | $                  | 0.42       |   | $ | 0.28 |   |
| Diluted earnings per share  |       | $                                                                     | 0.75       |               | $          | 0.45                |       | $                  | 0.41       |   | $ | 0.27 |   |
| **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 |   |

 

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

 

Thisfootnote provides unaudited information required by SFAS No. 69, *Disclosures About Oil and Natural Gas ProducingActivities*. The Company’s oil and natural gas properties are locatedwithin the United States of America, which constitutes one cost center.

 

***Capitalized Costs******-***Capitalized costs and accumulated depletionrelating to the Company’s oil and natural gas producing activities, all ofwhich are conducted within the continental United States, are summarized below:

 

| ** **                                 | ** ** | **December 31,** | ** **  |
|--------------------------------------------|------------|-----------------------|-------------|
| ** **                                 | ** ** | **2005**              | ** **  | **2004** | ** ** |
| Developed oil and natural gas properties   |       | $                     | 401,697,031 |   | $ | 243,187,690 |   |
| Unevaluated oil and natural gas properties |       | 36,948,399            |        | 15,490,704 |   |
| Accumulated depletion                      |       | (133,449,275          | )           | (93,639,018 | ) |
| Net capitalized cost                       |       | $                     | 305,196,155 |   | $ | 165,039,376 |   |

 

F-31

----

 

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

 
| ** **            | ** ** | **Year Ended December 31,** | ** **  |
|-----------------------|------------|--------------------------------------------|-------------|
| ** **            | ** ** | **2005**                                   | ** **  | **2004** | ** ** | **2003** | ** ** |
| Acquisition cost:     |       |                                       |        |   |   |   |   |
| Unproved properties   |       | $                                          | 33,948,056  |   | $ | 12,162,649 |   | $ | 6,052,137 |   |
| Proved properties (1) |       | 66,471,764                                 |        | 33,980,135 |   | 10,373,529 |   |
| Exploration costs     |       | 20,426,182                                 |        | 8,297,370 |   | 6,016,951 |   |
| Development costs (2) |       | 59,121,034                                 |        | 34,826,535 |   | 13,168,983 |   |
| Total costs incurred  |       | $                                          | 179,967,036 |   | $ | 89,266,689 |   | $ | 35,611,600 |   |

 

----

(1)   Includes$17.8 million added to property acquired in the Cinco acquisition associatedwith recording a deferred tax liability at the date of acquisition for taxabletemporary differences existing at the purchase date in accordance with SFAS No.109 (see Notes 6 and 14).

(2)          Included in Development costs line item arethe asset retirement costs associated with the plugging and abandonmentliability related to SFAS No. 143 (see Note 7). For 2003, $640,400 related tothe cumulative effect of the adoption of SFAS No. 143 on January 1, 2003 isexcluded from Development costs line item.

 

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

 

***Results of Operations -*** Results of operations for the Company’s oil and natural gas producingactivities are summarized below:

 
| ** **                                                   | ** ** | **Year Ended December 31,** | ** **  |
|--------------------------------------------------------------|------------|--------------------------------------------|-------------|
| ** **                                                   | ** ** | **2005**                                   | ** **  | **2004** | ** ** | **2003** | ** ** |
| Oil and natural gas revenue                                  |       | $                                          | 121,183,089 |   | $ | 64,505,348 |   | $ | 33,926,007 |   |
| Operating expenses:                                          |       |                                       |        |   |   |   |   |
| Oil and natural gas operating expenses and  ad valorem taxes |       | 10,102,294                                 |        | 5,356,246 |   | 3,109,392 |   |
| Production taxes                                             |       | 6,965,715                                  |        | 3,952,524 |   | 2,006,402 |   |
| Accretion expense                                            |       | 141,120                                    |        | 98,968 |   | 66,625 |   |
| Depletion expense                                            |       | 39,810,257                                 |        | 21,471,606 |   | 12,906,956 |   |
| Income tax expense                                           |       | 22,550,339                                 |        | 11,870,521 |   | 5,814,209 |   |
| Results of operations from oil and gas  producing activities |       | $                                          | 41,613,364  |   | $ | 21,755,483 |   | $ | 10,022,423 |   |

 

***Reserves -***Proved reserves are estimated quantities ofoil and natural gas, which geological and engineering data demonstrate withreasonable certainty to be, recoverable in future years from known reservoirsunder existing economic and operating conditions. Proved developed reserves areproved reserves that can reasonably be expected to be recovered throughexisting wells with existing equipment and operating 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 inaccordance with guidelines established by the SEC.

 

TheCompany’s net ownership in estimated quantities of proved oil and natural gasreserves and changes in net proved reserves, all of which are located in the continentalUnited States, are summarized below.

 

F-32

----

 
| ** **                                | ** ** | **Natural Gas  (Mcf)  Year Ended December 31,** | ** ** |
|-------------------------------------------|------------|---------------------------------------------------------------------|------------|
| ** **                                | ** ** | **2005**                                                            | ** ** | **2004** | ** ** | **2003** | ** ** |
| Proved developed and undeveloped reserves |       |                                                                |       |   |   |   |   |
| Beginning of year                         |       | 66,311,100                                                          |       | 46,824,000 |   | 34,980,000 |   |
| Revisions of previous estimates           |       | (7,736,992                                                          | )          | (5,993,260 | ) | (486,143 | ) |
| Purchase of oil and gas properties        |       | 10,167,821                                                          |       | 14,803,000 |   | 8,437,000 |   |
| Extensions and discoveries                |       | 26,144,571                                                          |       | 19,825,551 |   | 10,248,298 |   |
| Sales of natural gas properties           |       | —                                                              |       | — |   | (65,100 | ) |
| Production                                |       | (12,596,503                                                         | )          | (9,148,191 | ) | (6,290,055 | ) |
| End of year                               |       | 82,289,997                                                          |       | 66,311,100 |   | 46,824,000 |   |
|                                      |       |                                                                |       |   |   |   |   |
| Proved developed reserves at year end     |       | 59,065,900                                                          |       | 50,698,000 |   | 36,938,000 |   |

 
| ** **                                | ** ** | **Oil, Condensate and Natural Gas Liquids  (Bbls)  Year Ended December 31,** | ** ** |
|-------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------------|------------|
| ** **                                | ** ** | **2005**                                                                                                             | ** ** | **2004** | ** ** | **2003** | ** ** |
| Proved developed and undeveloped reserves |       |                                                                                                                 |       |   |   |   |   |
| Beginning of year                         |       | 3,791,626                                                                                                            |       | 2,851,072 |   | 2,342,315 |   |
| Revisions of previous estimates           |       | (639,951                                                                                                             | )          | (106,133 | ) | (46,348 | ) |
| Purchase of oil and gas properties        |       | 114,535                                                                                                              |       | 267,354 |   | 387,743 |   |
| Extensions and discoveries                |       | 775,444                                                                                                              |       | 1,270,134 |   | 472,904 |   |
| Sales of natural gas properties           |       | —                                                                                                               |       | — |   | (5,058 | ) |
| Production                                |       | (631,236                                                                                                             | )          | (490,801 | ) | (300,484 | ) |
| End of year                               |       | 3,410,418                                                                                                            |       | 3,791,626 |   | 2,851,072 |   |
|                                      |       |                                                                                                                 |       |   |   |   |   |
| Proved developed reserves at year end     |       | 2,851,872                                                                                                            |       | 2,698,125 |   | 2,104,610 |   |

 

***Standardized Measure******-***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, 2005 is shown below:

 
| ** **                                                | ** ** | **Year Ended December 31,** | ** **  |
|-----------------------------------------------------------|------------|--------------------------------------------|-------------|
| ** **                                                | ** ** | **2005**                                   | ** **  | **2004** | ** ** | **2003** | ** ** |
|                                                      |       |                                       |        |   |   |   |   |
| Future cash inflows                                       |       | $                                          | 949,752,406 |   | $ | 521,262,763 |   | $ | 350,187,406 |   |
| Future oil and natural gas operating  expenses            |       | (192,550,232                               | )           | (118,492,193 | ) | (75,208,036 | ) |
| Future development costs                                  |       | (79,651,234                                | )           | (31,794,903 | ) | (13,203,914 | ) |
| Future income tax expense                                 |       | (173,019,262                               | )           | (75,094,884 | ) | (53,902,855 | ) |
| Future net cash flows                                     |       | 504,531,678                                |        | 295,880,783 |   | 207,872,601 |   |
| 10% discount factor                                       |       | (160,742,129                               | )           | (79,009,770 | ) | (55,705,257 | ) |
| Standardized measure of discounted future  net cash flows |       | $                                          | 343,789,549 |   | $ | 216,871,013 |   | $ | 152,167,344 |   |

 

Inaccordance with SEC regulations, the year-end oil and natural gas prices ineffect at December 31, 2005, adjusted for basis and quality differentials, areapplied to year-end quantities of proved oil and natural gas reserves tocompute future cash flows. The base prices before adjustments were $10.05 perMMbtu of natural gas, $36.62 per Bbl of natural gas liquids and $61.04 per Bblof oil. In the normal course of business the Company enters into hedgingtransactions, including commodity price collars, swaps and floors to mitigateexposure to commodity price movements, but not for trading or speculativepurposes. During 2005, the Company put in place several natural gas and crudeoil collars for a portion of its 2006 production to achieve a more predictablecash flow. As of December 31, 2005, hedge contracts cover approximately 48% and37% of anticipated 2006 natural gas and crude oil production, respectively,before any future acquisitions. The prices used in calculating the standardizedmeasure fall within the limits of all the hedge transaction collars, thereforethere would be no impact to the standardized measure by these hedgetransactions.

 

F-33

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Futureoil and natural gas operating expenses and development costs are computedprimarily by the Company’s internal petroleum engineers and are provided toexternal independent petroleum engineers as estimates of expenditures to beincurred in developing and producing the Company’s proved oil and natural gasreserves at the end of the year, based on year-end costs and assuming thecontinuation of existing economic conditions.

 

Future income taxes arebased on year-end statutory rates, adjusted for net operating losscarryforwards and tax credits. A discount factor of 10% was used to reflect thetiming of future net cash flows. The Standardized Measure of Discounted FutureNet Cash Flows is not intended to represent the replacement cost or fair marketvalue of the Company’s oil and natural gas properties.

 

TheStandardized Measure of Discounted Future Net Cash Flows does not purport, norshould it be interpreted, to present the fair value of the Company’s oil andnatural gas reserves. An estimate of fair value would also take into account,among other things, the recovery of reserves not presently classified asproved, anticipated future changes in prices and costs, a discount factor morerepresentative of the time value of money and the risks inherent in reserveestimates.

 

***Changes in Standardized Measure******-***Changes in Standardized Measure of DiscountedFuture Net Cash Flows relating to proved oil and gas reserves are summarizedbelow:

 
| ** **                                                                   | ** ** | **Year Ended December 31,** | ** **   |
|------------------------------------------------------------------------------|------------|--------------------------------------------|--------------|
| ** **                                                                   | ** ** | **2005**                                   | ** **   | **2004** | ** ** | **2003** | ** ** |
| Changes due to current year operations:                                      |       |                                       |         |   |   |   |   |
| Sales of oil and natural gas, net of oil  and natural gas operating expenses |       | $                                          | (105,637,660 | ) | $ | (56,968,998 | ) | $ | (33,393,818 | ) |
| Sales of oil and natural gas properties                                      |       | —                                     |         | — |   | (356,195 | ) |
| Purchase of oil and gas properties                                           |       | 58,021,976                                 |         | 65,402,748 |   | 28,079,806 |   |
| Extensions and discoveries                                                   |       | 119,849,893                                |         | 65,466,396 |   | 33,535,443 |   |
| Changes due to revisions of standardized  variables:                         |       |                                       |         |   |   |   |   |
| Prices and operating expenses                                                |       | 143,599,377                                |         | 17,648,293 |   | 32,213,734 |   |
| Revisions of previous quantity estimates                                     |       | (54,208,263                                | )            | (21,190,007 | ) | (2,395,449 | ) |
| Estimated future development costs                                           |       | 14,054,334                                 |         | (15,961,730 | ) | (2,295,084 | ) |
| Income taxes                                                                 |       | (74,280,651                                | )            | (9,189,919 | ) | (7,585,409 | ) |
| Accretion of discount                                                        |       | 21,687,101                                 |         | 15,216,734 |   | 9,755,647 |   |
| Production rates (timing) and other                                          |       | 3,832,429                                  |         | 4,280,152 |   | (2,947,803 | ) |
| Net change                                                                   |       | 126,918,536                                |         | 64,703,669 |   | 54,610,872 |   |
| Beginning of year                                                            |       | 216,871,013                                |         | 152,167,344 |   | 97,556,472 |   |
| End of year                                                                  |       | $                                          | 343,789,549  |   | $ | 216,871,013 |   | $ | 152,167,344 |   |

 

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

 

F-34

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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 as of October 7, 2004 (Incorporated by reference from exhibit 2.1 to  the Company’s Current Report on Form 8-K filed October 12, 2004).                                                                                                                                                                                                                       |
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 2.4             |       | —     |       | Purchase  and Sale Agreement, dated as of September 21, 2005 among Pearl Energy  Partners, Ltd., and Cibola Exploration Partners, L.P., as Sellers; and Edge  Petroleum Exploration Company as Buyer and Edge Petroleum Corporation as  Guarantor (Incorporated by reference from exhibit 2.1 to the Company’s  Current Report on Form 8-K filed October 19, 2005).                                                                                                                                                                  |
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 2.5             |       | —     |       | Stock  Purchase Agreement by and among Jon L. Glass, Craig D. Pollard, Leigh T.  Prieto, Yorktown Energy Partners V, L.P., Yorktown Energy Partners VI, L.P.,  Cinco Energy Corporation, and Edge Petroleum Exploration Company and Edge  Petroleum Corporation, dated as of September 21, 2005 (Incorporated by  reference from exhibit 2.5 to the Company’s Quarterly Report on Form 10-Q for  the quarterly period ended September 30, 2005).                                                                                     |
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 2.6             |       | —     |       | Letter  Agreement dated November 18, 2005 by and among Edge Petroleum Exploration  Company, Cinco Energy Corporation and Sellers (Incorporated by reference from  exhibit 2.02 to the Company’s Current Report on Form 8-K filed December 6,  2005). Pursuant to Item 601(b)(2) of Regulation S-K, the Company had omitted  certain Schedules to the Letter Agreement (all of which are listed therein)  from this Exhibit 2.6. It hereby agrees to furnish a supplemental copy of any  such omitted item to the SEC on its request. |
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 3.1             |       | —     |       | Restated  Certificate of Incorporation of the Company effective January 27, 1997  (Incorporated by reference from exhibit 3.1 to the Company’s Current Report  on Form 8-K filed April 29, 2005).                                                                                                                                                                                                                                                                                                                                    |
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 3.2             |       | —     |       | Certificate  of Amendment to the Restated Certificate of Incorporation of the Company  effective January 31, 1997 (Incorporated by reference from exhibit 3.2 to the  Company’s Current Report on Form 8-K filed April 29, 2005).                                                                                                                                                                                                                                                                                                    |
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 3.3             |       | —     |       | Certificate  of Amendment to the Restated Certificate of Incorporation of the Company  effective April 27, 2005 (Incorporated by reference from exhibit 3.3 to the  Company’s Current Report on Form 8-K filed April 29, 2005).                                                                                                                                                                                                                                                                                                      |
|            |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 3.4             |       | —     |       | 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).                                                                                                                                                                                                                                                                                                                                                              |

 

F-35

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| 3.5        |   | — |   | 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).                                                                                                                                                                                                                                                                                                                                         |
|------------|--------|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 3.6        |   | — |   | 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        |   | — |   | Agreement  and Amendment No. 1 to Third Amended and Restated Credit Agreement dated May  31, 2005 among Edge Petroleum Corporation, Edge Petroleum Exploration  Company, Edge Petroleum Operating Company, Inc., Miller Exploration Company  and Miller Oil Corporation, as borrowers, the lenders thereto and Union Bank  of California, N.A., a national banking association, as agent for the lenders  (Incorporated by reference from Exhibit 4.2 to the Company’s Quarterly Report  on Form 10-Q for the quarterly period ended June 30, 2005). |
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| *4.3       |   | — |   | Agreement  and Amendment No. 2 to the Third Amended and Restated Credit Agreement dated  November 30, 2005 among Edge Petroleum Corporation, Edge Petroleum  Exploration Company, Edge Petroleum Operating Company, Inc., Miller Oil Corporation,  Miller Exploration Company, and Cinco Energy Corporation, as borrowers, the  lenders thereto and Union Bank of California, N.A., a national banking  association, as Agent.                                                                                                                            |
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 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)).                                                                                                                                                                                                                                                                                                                                             |

 

F-36

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| †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 therein (Incorporated by reference from exhibit 10.4 to the  Company’s Quarterly Report on Form 10-Q for the quarterly period ended  September 30, 1999).                                                                   |
|             |   |   |   |                                                                                                                                                                                                                                                                                                                                    |
| †10.8— |   |   |   | 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).                                                                        |
|             |   |   |   |                                                                                                                                                                                                                                                                                                                                    |
| †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 2005 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.                                                                                                                                                                                                                                                                                                   |

 

F-37

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| *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, 2005.                                                                                                                               |
|   |   |   |   |                                                                                                                                                                                                                          |
| *99.2  |   | — |   | Summary  of Reserve Report of W. D. Von Gonten & Co. Petroleum Engineers as of  December 31, 2005.                                                                                                                        |

 

----

*Filed herewith.

 

† Denotes management or compensatory contract, arrangement or agreement.

 

F-38

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