**UNITEDSTATES SECURITIES AND EXCHANGE COMMISSION**

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

#### **FORM10-K**

| **x**                                            | ** ** | **ANNUAL  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**     |
|--------------------------------------------------|------------|-----------------------------------------------------------------------------------------------|
|                                             |       |                                                                                          |
| **For the  fiscal year ended December 31, 2006** |
|                                             |       |                                                                                          |
| **OR**                                           |
|                                             |       |                                                                                          |
| **o**                                            | ** ** | **TRANSITION  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934** |

 

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

**Commission file number:  0-22149**

#### **EDGEPETROLEUM CORPORATION**

(Exact name ofRegistrant as specified in its charter)

| **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’stelephone number, including area code)

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Securitiesregistered pursuant to Section 12(b) of the Act:

| **Title of each class**                         |   | **Name of  each exchange on which registered** |
|-------------------------------------------------|--------|------------------------------------------------|
| Common Stock, Par Value $0.01 Per Share         |   | NASDAQ                                         |
| 5.75% Series A Cumulative Convertible Perpetual |   | NASDAQ                                         |
| Preferred Stock, Par Value $0.01 Per Share      |   |                                           |

 

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

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Indicate by check mark if the registrant is awell-known seasoned issuer, as defined in Rule 405 of the Securities Act.

o Yes  x No

Indicate by check mark if the registrant is notrequired to file reports pursuant to Section 13 or Section 15(d) of the Act.

 ̈ Yes  x No

Indicate bycheck mark whether the registrant (1) has filed all reports required to befiled by Section 13 or 15(d) of the Securities Exchange Act of 1934 during thepreceding 12 months (or for such shorter period that the registrant wasrequired to file such reports), and (2) has been subject to such filingrequirements for the past 90 days.        x Yes  o No

Indicate bycheck 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.       x

Indicate by check mark whether the registrant isa large accelerated filer, an accelerated filer, or a non-accelerated filer.See definition of “accelerated filer and larger accelerated filer” in Rule12b-2 of the Exchange Act.:

o Largeaccelerated filer          x AcceleratedFiler                  o Non-acceleratedfiler

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

As of June 30, 2006, theaggregate market value of the voting stock held by non-affiliates of theregistrant was $334.3 million (based on a value of $19.98 per share, theclosing price of the Common Stock as quoted by NASDAQ Global Select Market onsuch date).

As of March 8, 2007, 28,383,455 shares of CommonStock, par value $.01 per share, were outstanding.

DOCUMENTS INCORPORATED BYREFERENCE

***Portions ofthe definitive proxy statement for the registrant’s 2007 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.***       | *** *** | ***QUANTITATIVE  AND QUALITATIVE 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,  EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE***                                                             | *** *** | *** *** |
| *** ***         | *** *** | *** ***                                                                                                              | *** *** | *** *** |
| ***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, AND DIRECTOR INDEPENDENCE***                                          | *** *** | *** *** |
| *** ***         | *** *** | *** ***                                                                                                              | *** *** | *** *** |
| ***ITEM 14.***       | *** *** | ***PRINCIPAL ACCOUNTANT  FEES AND SERVICES***                                                                             | *** *** | *** *** |
|                 |         |                                                                                                                      | *** *** | *** *** |
| *** ***         | *** *** | *** ***                                                                                                              | *** *** | *** *** |
| *** ***         | ** **   | **PART IV**                                                                                                               | *** *** | *** *** |
| *** ***         | ** **   | ** **                                                                                                                | *** *** | *** *** |
| ***ITEM 15.***       | *** *** | ***EXHIBITS AND  FINANCIAL STATEMENT SCHEDULES***                                                                         | *** *** | *** *** |

 

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

*Unless otherwise indicated by the context,references herein to the “Company”, “Edge”, “we”, “our” or “us” mean EdgePetroleum Corporation, a Delaware corporation, and its corporate andpartnership subsidiaries and predecessors. Certain terms used herein relating to the oil and natural gas industryare defined in ITEMS 1 AND 2. “BUSINESS AND PROPERTIES –*CERTAIN DEFINITIONS.*”*

**FORWARD LOOKING INFORMATION**

Certainof the statements contained in all parts of this Annual Report on Form 10-Kincluding, but not limited to, those relating to our drilling plans (includingscheduled and budgeted wells), the effect of changes in strategy and businessdiscipline, future tax matters, our 3-D project portfolio, future general andadministrative expenses on a per unit of production basis, changes in wellsoperated and reserves, future growth and expansion, future exploration, futureseismic data (including timing and results), expansion of operation, ourability to generate additional prospects, review of outside generated prospectsand acquisitions, additional reserves and reserve increases, replace productionand manage our asset base, enhancement of visualization and interpretationstrengths, expansion and improvement of capabilities, integration of newtechnology into operations, credit facilities, redetermination of our borrowingbase, attraction of new members to the technical team, future compensationprograms, new focus on core areas, new prospects and drilling locations, newalliances, future capital expenditures (or funding thereof) and workingcapital, sufficiency of future working capital, borrowings and capitalresources and liquidity, projected rates of return, retained earnings anddividend policies, projected cash flows from operations, future commodity priceenvironment, expectation or timing of reaching payout, outcome, effects or timingof any legal proceedings or contingencies, the impact of any change in accounting policies on our financialstatements, the number, timing or results of any wells, the plans for timing,interpretation and results of new or existing seismic surveys or seismic data,future production or reserves, future acquisition of leases, lease options orother land rights, any other statements regarding future operations, financialresults, opportunities, growth, business plans and strategy and otherstatements that are not historical facts are forward-looking statements.  These forward-looking statements reflect ourcurrent view of future events and financial performance.  When used in this document, the words “budgeted,”“anticipate,” “estimate,” “expect,” “may,” “project,” “believe,” “intend,” “plan,”“potential,” “forecast,” “might,” “predict,” “should” and similar expressionsare intended to be among the expressions that identify forward-lookingstatements. These forward-looking statements speak only as of their datesand should not be unduly relied upon.  Weundertake no obligation to publicly update or revise any forward-lookingstatement, whether as a result of new information, future events, orotherwise.   Such statements involverisks and uncertainties, including, but not limited to, those set forth under *ITEM 1A. “**RISK FACTORS”* and other factors detailed inthis document and our other filings with the Securities and ExchangeCommission.  Should one or more of theserisks or uncertainties materialize, or should underlying assumptions proveincorrect, actual outcomes may vary materially from those indicated.  All subsequent written and oralforward-looking statements attributable to us or to persons acting on ourbehalf are expressly qualified in their entirety by reference to these risksand uncertainties.

**AVAILABLE  INFORMATION**

Ourwebsite address is www.edgepet.com.  Wemake our website content available for information purposes only.  It should not be relied upon for investmentpurposes, nor is it incorporated by reference in this Form 10-K. We makeavailable on this website under “Investor Relations - SEC Filings,” free ofcharge, our annual reports on Form 10-K, quarterly reports on Form 10-Q,current reports on Form 8-K and amendments to those reports as soon asreasonably practicable after we electronically file those materials with, orfurnish those materials to, the Securities and Exchange 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**

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

###### **Overview**

EdgePetroleum Corporation is an independent oil and natural gas company engaged inthe exploration, development, acquisition and production of crude oil andnatural gas properties in the United States. Edge was founded in 1983 as aprivate company and went public in 1997. We have evolved over time from a prospect generation organizationfocused on high-risk, high-reward exploration projects to a team-driven organizationfocused on a balanced program of exploration, exploitation, development andacquisition of oil and natural gas properties. Following a top-level managementchange in late 1998, a more disciplined style of business planning andmanagement was integrated into our technology-driven drilling activities andstrategy. We believe the continuation of this disciplined business model andstrategy will result in continued growth in reserves, production and financialstrength and flexibility.

# **Recent Developments &Accomplishments**

*Overview*

At year-end 2006, our netproved reserves were 102.1 Bcfe, comprised of 76.1 billion cubic feet ofnatural gas, 1.9 million barrels of natural gas liquids and 2.4 million barrelsof crude oil and condensate. Natural gas and natural gas liquids accounted forapproximately 86% of those proved reserves. Approximately 77% of total proved reserves were developed as of year-end2006 and they were all located onshore, in the United States. During 2006, wefocused on developing and exploiting assets in south Texas, our largest corearea.  Our 2006 drilling program did notmeet our expectations as it was adversely impacted by drilling delays on ournonoperated properties, mainly at the Chapman Ranch Field, shortages ofoilfield services and qualified personnel, and the drilling of a larger thanoriginally planned number of proved undeveloped locations.  These events, along with falling natural gasprices, the disappointment of drilling a total of nine dry holes, and thedeferment of portions of our drilling program targeting potential new reserves,including the Chapman Ranch Field properties, resulted in a slight decrease inour estimated proved reserves at December 31, 2006 of 102.1 Bcfe compared tothe prior year of 102.8 Bcfe.  Despitethese factors, we were able to drill 52 wells with an apparent success rate of83% in 2006.  As described below, inDecember 2006, we completed an acquisition involving additional workinginterests and operatorship in the Chapman Ranch Field, where we already ownedworking interests as a result of two acquisitions late in 2005.  Obtaining operatorship strategicallypositions us in 2007 and beyond to develop and exploit what we believe is anessential asset in our south Texas portfolio.

*Kerr-McGee Acquisition*

On December 28, 2006, wecompleted an acquisition of certain working interests in the Chapman RanchField from Kerr-McGee Oil and Gas Onshore, L.P. (“Kerr-McGee”), a wholly-ownedsubsidiary of Anadarko Petroleum Corporation, for approximately $25 million(the “Kerr-McGee acquisition”). In late 2005, we acquired working interests inthis field, including interests in several producing wells, ranging fromapproximately 44% to 50%. In the Kerr-McGee acquisition, we acquired anadditional 44% to 50% working interest in the same wells in the field, andacquired two additional wells, bringing our working interests in those ChapmanRanch properties, including a total of nine producing wells, to 88% to 100%. Asof December 31, 2006, the Kerr-McGee assets had approximately 9.0 Bcfe ofproved reserves, of which approximately 30% were proved developed. We financedthe acquisition with borrowings under our then-existing credit facility.

*Smith Acquisition*

On January 31, 2007, wecompleted the purchase of certain oil and natural gas properties located in 13counties in south and southeast Texas and other associated assets from SmithProduction Inc. (“Smith”). We paid approximately $389.8 million for theseassets (“Smith assets”).  Although a 2007event for us, as of December 31, 2006, the Smith assets contained approximately123.0 Bcfe of proved reserves, which were 81% natural gas and 64% proveddeveloped. In total, the Smith assets include approximately 150 gross producingwells (74 net) and an ownership interest in approximately 17,000 gross (12,250net) developed acres and 56,000 gross (16,000 net) undeveloped acres ofleasehold, all as of December 31, 2006.

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In addition to theproperties and related acreage, we acquired from Smith certain gatheringfacilities and ownership of approximately 13 miles of natural gas gatheringpipelines and related infrastructure serving certain producing assets insoutheast Texas. The pipeline system transports our natural gas as well asthird-party natural gas.

We also acquired 25% ofSmith’s option and leasehold rights in an approximate 95 square mile 3-Dexploration area with approximately 30,000 gross acres of leases and optionslocated in the Mission project area in Hidalgo County in south Texas, with aprimary focus on the Vicksburg formation. We acquired a 12.5% working interest in an approximate 160 square mile3-D exploration area with approximately 55,000 gross acres of leases andoptions located in the Yates Ranch/Hostetter project area in McMullen and DuvalCounties in south Texas. The 160 mile 3-D area increases our exposure to theMiddle and Deep Wilcox trend. Furthermore, this venture allows us toparticipate in a proposed additional 3-D shoot covering approximately120 square miles near the Yates Ranch within the Wilcox trend. We alsoacquired 25% of Smith’s option and leasehold rights in an approximate 105square mile 3-D exploration area with approximately 60,000 gross acres ofleases and options in Newton County in southeast Texas and Beauregard Parish inLouisiana with a focus on prospects in the Frio, Yegua and Wilcox formations atdepths ranging between 4,000 and 10,000 feet.

*Public Offerings*

In January 2007, wecompleted concurrent public offerings of 10,925,000 shares of our common stockfor net proceeds of approximately $138.1 million and 2,875,000 shares of our5.75% Series A cumulative convertible perpetual preferred stock for netproceeds of approximately $138.6 million. We used the net proceeds from these offerings, along with borrowingsunder our current credit facility, to finance the Smith acquisition and torepay our prior credit facility.

# **Strategy**

Our business strategy is based onthe following six main elements:

*1. Growreserves through acquisitions and the drilling of a balanced portfolio ofprospects.*We seek tomaintain a prudent balance between higher risk/reward wells and more moderaterisk/reward wells. In 2006, we drilled 52 wells (28.93 net), primarily inTexas, with 43 (23.40 net) of those wells completed as productive for anapparent success rate of approximately 83%. This drilling program, along withour acquisition of certain oil and gas assets on the Chapman Ranch Field,helped us to replace 97% of our production (see *“*Oil and Natural Gas Reserve Replacement”).  Over the last three years, we drilled 166wells (91.29 net).  Of the drilled wells,145 gross (78.27 net) have been completed as apparent successes, for a successrate of approximately 87%.  As a resultof our acquisitions and drilling program, we have grown production and provedreserves since December 31, 2004. Production has grown from 12.1 Bcfe at December 31, 2004 to 17.3 Bcfe atDecember 31, 2006, an increase of approximately 43%.  Also, we have grown proved reserves fromapproximately 89.1 Bcfe at year-end 2004 to 102.1 Bcfe at December 31,2006.  We expect our drilling program for2007 to be focused primarily in south Texas, and to a lesser extent in theMississippi Salt Basin, southeast New Mexico and the Fayetteville Shale inArkansas.  We expect to drill between 80and 90 wells (37 and 42 net, respectively) in 2007 and we estimate capitalspending for the year to be approximately $140 million. In addition, we have acontingent drilling program that could add wells and costs to this estimate.

*2. Seekacquisitions that we believe have upside potential*.  We seek acquisitions of producing propertiesthat typically have exploration or exploitation upside potential. Asillustrated by the Kerr-McGee acquisition and the Smith acquisition, weprimarily seek properties in our existing core areas or as a means to establishnew core areas. We continue to work diligently to identify and evaluateacquisition opportunities with the goal of implementing those that we believewould fit our strategic plan and add stockholder value.

*3. Focus onspecific geographic areas where we believe we can add value.*We believe geographic focus is a critical elementof success. Long-term success requires detailed knowledge of both geologic andgeophysical attributes, as well as operating conditions in the areas in whichwe operate. As a result, we focus on a select number of geographic areas whereour experience and strengths can be applied with a significant influence on theoutcome. We believe this focus will allow us to manage a growing asset base andadd value to additional properties while controlling incremental costs andstaffing requirements.

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*4. Integratetechnological advances into our exploration, drilling, production operationsand administration. *We use advanced technologies as risk-reductiontools in our exploration, development, drilling and completion activities. Dataanalysis and advanced processing techniques, combined with our more traditionalsub-surface interpretation techniques, allow our team of technical personnel tomore easily identify features, structural details and fluid contacts that couldbe overlooked using less sophisticated data interpretation techniques.

*5. Maintain aconservative financial structure and control our cost structure. *We believe that a conservative financial structure is crucial toconsistent, positive financial results, management of cyclical swings in ourindustry and the ability to move quickly to take advantage of acquisitions andattractive drilling opportunities. In order to maximize our financialflexibility, we try to maintain a target range of 30% to 40% for our totaldebt-to-capital ratio.  At December 31,2006, our debt-to-total capital ratio was 45.3%, resulting from the use of debtto finance our acquisition programs in 2005 and 2006.  Subsequent to December 31, 2006, we issued10,925,000 shares of common stock and 2,875,000 shares of 5.75% Series Acumulative convertible perpetual preferred stock, which reduced our totaldebt-to-capital ratio.

We try to fund most of our ongoing capital expenditures using cash flowfrom operations, reserving our debt capacity for potential investmentopportunities that we believe can profitably add to our program. Part of asound financial structure is constant attention to costs, both operating andoverhead. Over the past several years, we have worked diligently to control ouroperating and overhead costs and instituted a formal, disciplined budgetingprocess.

*6. Use equity ownership and performance based compensationprograms to attract and retain a high-quality workforce.*Following a management change in late 1998, weeliminated the previous overriding royalty compensation system and replaced itwith a system designed to reward all employees through performance-basedcompensation that is competitive with our peers and through equity ownership.As of February 28, 2007, our directors and employees, including executiveofficers, owned or had options to acquire an aggregate of approximately 7% ofour outstanding common stock.

**Employees**

Asof March 9, 2007, we had 75 full-time employees.  We believe that our relationships with ouremployees are good.  None of ouremployees are covered by a collective-bargaining agreement.  From time to time, we utilize the services ofindependent consultants and contractors to perform various professionalservices, particularly in the areas of construction, design, well-sitesurveillance, permitting and environmental assessment.  Field and on-site production operationservices, such as pumping, maintenance, dispatching, inspection and testing aregenerally provided by independent contractors.

**Offices**

Welease executive and corporate office space located in Travis Tower in Houston,Texas.

### **Oiland Natural Gas Reserves**

Thefollowing table sets forth our estimated net proved oil and natural gasreserves and the present value of estimated future net cash flows related tosuch reserves as of December 31, 2006. We engaged Ryder Scott Company, L.P. (“Ryder Scott”) and W. D. VonGonten & Co. (“WDVG”) to estimate our net proved reserves, projected futureproduction, estimated future net revenue attributable to our proved reserves,and the present value of such estimated future net revenue as of December 31,2006.  Ryder Scott and WDVG’s estimateswere based upon a review of production histories and other geologic, economic,ownership and engineering data provided by us. Ryder Scott has independently evaluated our reserves for the pastthirteen years and WDVG has independently reviewed the reserves we acquiredfrom Contango Oil and Gas Company late in 2004 for the past five years.  In estimating the reserve quantities that areeconomically recoverable, Ryder Scott and WDVG used oil and natural gas pricesin effect at December 31, 2006 and estimated development and production coststhat were in effect during December 2006 without giving effect to hedgingactivities.  In accordance with SECregulations, no price or cost escalation or reduction was considered by RyderScott and WDVG.  For further informationconcerning Ryder Scott and WDVG’s estimates of our proved reserves at December31, 2006, see the summaries of the reserve reports of Ryder Scott and WDVGincluded as exhibits to this Form 10-K (respectively, the “Ryder Scott Report”and the

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“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 after income taxes was prepared using constantprices as of the calculation date, discounted at 10% per annum, and is notintended to represent the current market value of the estimated oil and naturalgas reserves owned by us.  For furtherinformation concerning the present value of future net revenue from theseproved reserves, see Note 21 to our consolidated financial statements.  See also *ITEM 1A. “RISK FACTORS.”*  The oil and natural gas reserve data includedin or incorporated by reference in this document are only estimates and mayprove to be inaccurate.
| ** **                                                                                         | ** **   | **Proved Reserves as of December 31, 2006** | ** **   |
|----------------------------------------------------------------------------------------------------|--------------|---------------------------------------------------------------------------|--------------|
| ** **                                                                                         | ** **   | **Developed (1)**                                                    | ** **   | **Undeveloped (2)** | ** ** | **Total** | ** ** |
|                                                                                               |         |                                                                      |         |   |   |   |   |
| Oil and condensate  (MBbls)(3)                                                                     |         | 3,158                                                                     |         | 1,167 |   | 4,325 |   |
| Natural gas  (MMcf)                                                                                |         | 60,163                                                                    |         | 15,984 |   | 76,147 |   |
| Total MMcfe                                                                                        |         | 79,114                                                                    |         | 22,984 |   | 102,098 |   |
|                                                                                               |         |                                                                      |         |   |   |   |   |
| ***In  thousands:***                                                                               | *** *** | *** ***                                                              | *** *** | *** *** | *** *** | *** *** | *** *** |
| Estimated future  net revenue before income taxes                                                  |         | $                                                                         | 351,433      |   | $ | 57,857 |   | $ | 409,290 |   |
|                                                                                               |         |                                                                      |         |   |   |   |   |
| Present value of  estimated future net revenue before income taxes (discounted 10% per annum)  (4) |         | $                                                                         | 240,971      |   | $ | 30,545 |   | $ | 271,516 |   |
| Future income  taxes (discounted 10% per annum)                                                    |         | (35,116                                                                   | )            | (3,194 | ) | (38,310 | ) |
| Standardized measure of  discounted future net cash flows                                          |         | $                                                                         | 205,855      |   | $ | 27,351 |   | $ | 233,206 |   |

 

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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, 2006, whichwere $5.62 per MMbtu of natural gas and $61.06 per Bbl of oil. Managementbelieves that the presentation of the present value of future net cash flowsattributable to estimated proved reserves, discounted at 10% per annum (the “PV-10Value”), may be considered a non-GAAP financial measure as defined in Item 10(e)of Regulation S-K, therefore the Company has included this reconciliation ofthe measure to the most directly comparable GAAP financial measure(Standardized measure of discounted future net cash flows). Management believesthat the presentation of PV-10 Value provides useful information to investorsbecause it is widely used by professional analysts and sophisticated investorsin evaluating oil and gas companies. Because many factors that are unique toeach individual company may impact the amount of future income taxes to bepaid, the use of the pre-tax measure provides greater comparability whenevaluating companies. It is relevant and useful to investors for evaluating therelative monetary significance of the Company’s oil and natural gas properties.Further, investors may utilize the measure as a basis for comparison of therelative size and value of the Company’s reserves to other companies.Management also uses this pre-tax measure when assessing the potential returnon investment related to its oil and natural gas properties and in evaluatingacquisition candidates. The PV-10 Value is not a measure of financial oroperating performance under GAAP, nor is it intended to represent the currentmarket value of the estimated oil and natural gas reserves owned by theCompany. PV-10 Value should not be considered in isolation or as a substitutefor the standardized measure of discounted future net cash flows as definedunder GAAP.

Thereserve data set forth herein represents estimates only.  Reserve engineering is a subjective processof estimating underground accumulations of oil and natural gas that cannot bemeasured in an exact manner, and the accuracy of any reserve estimate is afunction of the quality of available data and of engineering and geologicalinterpretation and judgment.  As aresult, estimates made by different engineers often vary from one another.  In addition, results of drilling, testing andproduction subsequent to the date of an estimate may justify revision of suchestimates, and such revisions may be material. Accordingly, reserve estimates are generally different from thequantities of oil and natural gas that are ultimately recovered.  Furthermore, the estimated future net revenuefrom proved reserves and the present value thereof are based upon certainassumptions, including current prices, production levels and costs that may notbe what is actually incurred or realized. No estimates of proved reservescomparable to those included herein have been included in reports to any federalagency other than the SEC.

In accordance with SECregulations, the Ryder Scott Report and the WDVG Report each used year-end oiland natural gas prices in effect at December 31, 2006, adjusted for basis andquality differentials. The prices used in

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calculating the estimated future netrevenue attributable to proved reserves do not necessarily reflect marketprices for oil and natural gas production subsequent to December 31, 2006.There can be no assurance that all of the proved reserves will be produced andsold within the periods indicated, that the assumed prices will actually berealized for such production or that existing contracts will be honored orjudicially enforced. In particular, natural gas prices at December 31, 2006were significantly lower than natural gas prices in effect at the previousyear-end.  The average natural gas priceused in the December 31, 2005 estimation of pre-tax future net cash flows ofproved reserves, using a 10% discount rate (“PV10”), was $10.05 per MMBtu ofgas, which is considerably higher than the $5.62 per MMBtu used to calculatethe PV10 at December 31, 2006.  Decreasesin the assumed commodity prices result in decreases in estimated future netrevenue as well as in estimated reserves.

# **Oil and Natural Gas ReserveReplacement**

Findingand developing sufficient amounts of natural gas and crude oil reserves ateconomical costs are critical to our long-term success. Our business, as withother extractive businesses, is a depleting one in which each gas equivalentunit produced must be replaced or our asset base and ability to generaterevenues in the future will shrink. Given the inherent decline of reservesresulting from the production of those reserves, it is important for anexploration and production company to demonstrate a long-term trend of morethan offsetting produced volumes with new reserves that will provide for futureproduction. We use the reserve replacement ratio, as defined below, as anindicator of our ability to replenish annual production volumes and grow ourreserves, thereby providing some information on the sources of futureproduction and income. We believe that reserve replacement is relevant anduseful information that is commonly used by analysts, investors and otherinterested parties in the oil and gas industry as a means of evaluating theoperational performance and to a greater extent the prospects of entitiesengaged in the production and sale of depleting natural resources. Thesemeasures are often used as a metric to evaluate an entity’s historical trackrecord of replacing the reserves that it produced. The reserve replacementratio is calculated by dividing the sum of reserve additions from all sources(revisions, acquisitions, extensions and discoveries) by the actual productionfor the corresponding period. Additions to our reserves are proven developedand proven undeveloped reserves. We expect to continue adding to our reservebase through these activities, but certain factors outside our control mayimpede our ability to do so (see *ITEM 1A. “RISK FACTORS*”).The values for these reserve additions and production are derived directly fromthe proved reserves table in Note 21 to our consolidated financial statements.Accordingly, we do not use unproved reserve quantities.  The reserve replacement ratio is astatistical indicator that has limitations. As an annual measure, the ratio islimited because it typically varies widely based on the extent and timing ofnew discoveries and property acquisitions. Its predictive and comparative valueis also limited for the same reasons. In addition, since the ratio does notconsider the cost or timing of future production of new reserves, it cannot beused as a measure of value creation. The ratio does not distinguish betweenchanges in reserve quantities that are developed and those that will requireadditional time and funding to develop. In that regard, the percentage ofreserves that were developed was 77%, 74% and 75% for the years ended December31, 2006, 2005 and 2004, respectively. Set forth below is our reservereplacement ratio for the periods indicated. 
|                            | ** ** | **For the Year Ended December 31,** | ** ** | ** ** | ** ** |
|----------------------------|------------|--------------------------------------------------------------|------------|------------|------------|
| ** **                 | ** ** | **2006**                                                     | ** ** | **2005**   | ** ** | **2004** | ** ** | **Three Year Average** | ** ** |
| Reserve  Replacement Ratio |       | 97                                                           | %          | 184        | %          | 308 | % | 184 | % |

 

# **Oil and Natural Gas Volumes, Prices and OperatingExpense**

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

8

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| ** **                                                               | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                               | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Production:**                                                          | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil and  condensate (MBbls)                                              |       | 345                                        |       | 324 |   | 215 |   |
| Natural gas  liquids (MBbls)                                             |       | 222                                        |       | 308 |   | 276 |   |
| Natural gas  (MMcf)                                                      |       | 13,850                                     |       | 12,597 |   | 9,148 |   |
| Natural gas  equivalent (MMcfe)                                          |       | 17,251                                     |       | 16,384 |   | 12,093 |   |
| **Average sales price - before  hedging and derivatives:**               | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil and  condensate ($ per Bbl)                                     |       | $                                          | 63.10      |   | $ | 53.57 |   | $ | 39.77 |   |
| Natural gas  liquids ($ per Bbl)                                    |       | 25.52                                      |       | 18.45 |   | 15.83 |   |
| Natural gas ($ per  Mcf)                                            |       | 6.68                                       |       | 7.97 |   | 5.91 |   |
| Natural gas  equivalent ($ per Mcfe)                                |       | 6.96                                       |       | 7.53 |   | 5.54 |   |
| **Average sales price - after  hedging and derivatives:**                | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil and  condensate ($ per Bbl)                                     |       | $                                          | 64.10      |   | $ | 50.36 |   | $ | 33.03 |   |
| Natural gas  liquids ($ per Bbl)                                    |       | 25.52                                      |       | 18.45 |   | 15.83 |   |
| Natural gas ($ per  Mcf)                                            |       | 7.36                                       |       | 7.87 |   | 5.80 |   |
| Natural gas  equivalent ($ per Mcfe)                                |       | 7.52                                       |       | 7.40 |   | 5.33 |   |
| **Average oil and natural gas  operating expenses ($ per Mcfe)(1)** |       | $                                          | 0.53       |   | $ | 0.52 |   | $ | 0.41 |   |
| **Average production and ad valorem taxes ($ per  Mcfe)**           |       | $                                          | 0.53       |   | $ | 0.52 |   | $ | 0.36 |   |

 

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(1)          Includes direct lifting costs (labor, repairsand maintenance, materials and supplies), expensed workover costs, theadministrative costs of field production personnel, and insurance costs.

**Exploration, Development andAcquisition Capital Expenditures**

Thefollowing table sets forth certain information regarding the total costsincurred in connection with exploration, development and acquisitionactivities.
|                         | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------|------------|--------------------------------------------|------------|
| ** **              | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **              | ** ** | **(in thousands)**                    | ** ** |
| Acquisition  costs:     |       |                                       |       |   |   |   |   |
| Unproved properties     |       | $                                          | 21,661     |   | $ | 33,948 |   | $ | 12,163 |   |
| Proved properties (1)   |       | 36,573                                     |       | 66,472 |   | 33,980 |   |
| Exploration  costs      |       | 17,898                                     |       | 20,426 |   | 8,297 |   |
| Development  costs      |       | 64,724                                     |       | 58,685 |   | 34,549 |   |
| Subtotal                |       | 140,856                                    |       | 179,531 |   | 88,989 |   |
| Asset retirement  costs |       | 416                                        |       | 436 |   | 278 |   |
| Total costs  incurred   |       | $                                          | 141,272    |   | $ | 179,967 |   | $ | 89,267 |   |

 

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(1)          Includes $17.8 million added to propertyacquired in the Cinco acquisition in 2005 associated with recording a deferredtax liability at the date of acquisition for taxable temporary differencesexisting at the purchase date in accordance with SFAS No. 109, *Accounting for Income Taxes*.   This amount was adjusted to $16.8 million in2006 as a result of the final purchase price adjustment for the Cincoacquisition.  See Notes 6 and 15 to ourconsolidated financial statements.

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

**Drilling Activity**

Thefollowing table sets forth our drilling activity for the periodsindicated.  In the table, “Gross” refersto the total wells in which we have a working interest or back-in workinginterest after payout and “Net” refers to gross wells multiplied by our workinginterest therein.
|                   | ** ** | **Year Ended December 31,** | ** ** |
|-------------------|------------|--------------------------------------------|------------|
| ** **        | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **        | ** ** | **Gross**                                  | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Exploratory:**  |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Productive        |       | 13                                         |       | 5.12 |   | 16 |   | 6.44 |   | 5 |   | 2.35 |   |
| Non-productive    |       | 5                                          |       | 2.66 |   | 1 |   | 0.75 |   | 5 |   | 2.50 |   |
| Total             |       | 18                                         |       | 7.78 |   | 17 |   | 7.19 |   | 10 |   | 4.85 |   |
| **Development:**  |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Productive        |       | 30                                         |       | 18.28 |   | 46 |   | 26.51 |   | 35 |   | 19.33 |   |
| Non-productive    |       | 4                                          |       | 2.87 |   | 2 |   | 1.75 |   | 4 |   | 2.73 |   |
| Total             |       | 34                                         |       | 21.15 |   | 48 |   | 28.26 |   | 39 |   | 22.06 |   |
| **Grand  Total**  |       | 52                                         |       | 28.93 |   | 65 |   | 35.45 |   | 49 |   | 26.91 |   |
|              |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| **Success Ratio** | ** ** | **83**                                     | **%**      | **81** | **%** | **95** | **%** | **93** | **%** | **82** | **%** | **81** | **%** |

 

9

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# **Productive Wells**

Thefollowing table sets forth the number of productive oil and natural gas wellsin which we owned an interest as of December 31, 2006.
|             | ** ** | **Company-Operated** | ** ** | **Non-Operated** | ** ** | **Total** | ** ** |
|-------------|------------|----------------------|------------|------------------|------------|-----------|------------|
| ** **  | ** ** | **Gross**            | ** ** | **Net**          | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|        |       |                 |       |             |       |      |       |   |   |   |   |   |   |
| Oil         |       | 25                   |       | 12.59            |       | 72        |       | 19.45 |   | 97 |   | 32.04 |   |
| Natural gas |       | 87                   |       | 72.97            |       | 235       |       | 86.22 |   | 322 |   | 159.19 |   |
| Total       |       | 112                  |       | 85.56            |       | 307       |       | 105.67 |   | 419 |   | 191.23 |   |

 

# **Acreage Data**

Thefollowing table sets forth certain information regarding our developed andundeveloped lease acreage as of December 31, 2006.  Developed acres refer to acreage withinproducing units and undeveloped acres refer to acreage that has not been placedin producing units.
|             | ** ** | **Developed Acres** | ** ** | **Undeveloped Acres** | ** ** | **Total** | ** ** |
|-------------|------------|--------------------------|------------|----------------------------|------------|-----------|------------|
| ** **  | ** ** | **Gross**                | ** ** | **Net**                    | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|        |       |                     |       |                       |       |      |       |   |   |   |   |   |   |
| Arkansas    |       | —                   |       | —                     |       | 5,448     |       | 4,629 |   | 5,448 |   | 4,629 |   |
| Montana     |       | —                   |       | —                     |       | 12,446    |       | 9,329 |   | 12,446 |   | 9,329 |   |
| Michigan    |       | 160                      |       | 160                        |       | 498       |       | 498 |   | 658 |   | 658 |   |
| Alabama     |       | 750                      |       | 47                         |       | —    |       | — |   | 750 |   | 47 |   |
| Louisiana   |       | 1,906                    |       | 470                        |       | 236       |       | 126 |   | 2,142 |   | 596 |   |
| New Mexico  |       | 7,328                    |       | 2,281                      |       | 92,687    |       | 17,555 |   | 100,015 |   | 19,836 |   |
| Mississippi |       | 10,262                   |       | 3,220                      |       | 55,641    |       | 43,833 |   | 65,903 |   | 47,053 |   |
| Texas       |       | 60,139                   |       | 25,051                     |       | 14,412    |       | 5,918 |   | 74,551 |   | 30,969 |   |
| Total       |       | 80,545                   |       | 31,229                     |       | 181,368   |       | 81,888 |   | 261,913 |   | 113,117 |   |

 

Leasescovering approximately 15,404 gross (11,793 net), 24,716 gross (19,984 net) and17,248 gross (12,178 net) undeveloped acres are scheduled to expire in 2007,2008 and 2009, respectively.  In general,our leases will continue past their primary terms if oil and natural gasproduction in commercial quantities is being produced from a well on such leaseor other drilling or reworking operations are being continuously prosecuted.

### The table above does not include 93,362 gross(41,785 net) undeveloped acres in Texas for which we have the option to acquireleases based upon a commitment of continuous drilling subject to the following:

| Options Expire* | ** ** | **Gross Acres** | ** ** | **Net Acres** | ** ** |
|----------------------|------------|----------------------|------------|--------------------|------------|
| 2007                 |       | 92,351               |       | 41,613             | ** ** |
| 2008                 |       | 1,011                |       | 172                | ** ** |
| Total                |       | 93,362               |       | 41,785             | ** ** |

 

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###### * This is an estimate of the expiration of our optionto acquire leased acreage based on our current well and 3-D seismic acquisitionschedule.

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# **Core Areas of Operation**

Asof December 31, 2006, 70% of our proved reserves were in south Texas, 14% inMississippi, 8% in New Mexico, and 8% in south Louisiana, Michigan, Alabama andArkansas.  During 2006, we added reservesand production through our drilling program, focused in south Texas, and ouracquisition program.

Thetable below sets forth the gross and net number of our gas, oil and servicewells in each of our core areas of operation as of December 31, 2006.
|             | ** ** | **Gas Wells** | ** ** | **Oil Wells** | ** ** | **Service Wells (1)** | ** ** |
|-------------|------------|--------------------|------------|--------------------|------------|---------------------------------|------------|
| ** **  | ** ** | **Gross**          | ** ** | **Net**            | ** ** | **Gross**                       | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Texas       |       | 289                |       | 145.27             |       | 42                              |       | 17.24 |   | 4 |   | 1.90 |   |
| Louisiana   |       | 6                  |       | 1.16               |       | —                          |       | — |   | 3 |   | 0.64 |   |
| Mississippi |       | 9                  |       | 5.44               |       | 25                              |       | 5.00 |   | 4 |   | 1.57 |   |
| Alabama     |       | —             |       | —             |       | 5                               |       | 0.22 |   | 3 |   | 0.26 |   |
| Michigan    |       | 1                  |       | 1.00               |       | —                          |       | — |   | — |   | — |   |
| New Mexico  |       | 17                 |       | 6.32               |       | 25                              |       | 9.58 |   | — |   | — |   |
| Total       |       | 322                |       | 159.19             |       | 97                              |       | 32.04 |   | 14 |   | 4.37 |   |

 

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(1)          Service wells are wells drilled or completedfor the purpose of supporting production in an existing field. Specificpurposes of service wells include gas injection, water injection, steaminjection, air injection, salt-water disposal, water supply for injection,observation, or injection for in-situ combustion.

# *Texas*

Asof December 31, 2006, we owned an interest in 74,551 gross (30,969 net) acresin south Texas.  Our areas of focus inthis region are predominantly in the Wilcox, Queen City, Vicksburg and Frioproducing trends. As of December 31, 2006, we operated approximately 80producing wells, which along with our 255 non-operated wells accounted forabout 81% of our total net production in 2006. We drilled 33 wells during 2006 in Texas, 76% of which were an apparentsuccess. The majority of our 2006 drilling activity took place in the QueenCity project area. We drilled 21 apparently successful wells in the Queen Cityproject area, one at Chapman Ranch and one at Encinitas.  In 2007, we currently expect to drill 45 to49 wells (23 to 25 net, respectively) in our core areas in Texas.  The majority of these wells are planned inthe Vicksburg, Frio, Wilcox and Queen City project areas.

# *South Louisiana*

As ofDecember 31, 2006, we owned an interest in 2,142 gross (596 net) acres in southLouisiana primarily located in Acadia, Calcasieu, Lafayette, St. Landry andVermilion Parishes. As of December 31, 2006, we had an interest in 9 wells,none of which we operate. We did not drill any wells in south Louisiana in 2006and we have no current plans to drill additional wells in this area in2007.  We did, however, acquire newproperties in Louisiana in our Smith acquisition in 2007.

# *Mississippi Interior Salt Basin*

Asof December 31, 2006, we owned an interest in 65,903 gross (47,053 net) acresin the Mississippi Interior Salt Basin area, including undeveloped acreage inthe Floyd Shale play. We acquired reserves and production in the MississippiInterior Salt Basin in south central Mississippi as part of the 2003 mergerwith Miller Exploration Company (“Miller”). The primary producing horizons in the Mississippi Interior Salt Basinaround the Miller properties include the Hosston, Sligo, Rodessa and James Limesections.  As of December 31, 2006, weoperated eleven producing wells in this area. Production from wells in the Mississippi Interior Salt Basin accountedfor approximately 7% of our total net production in 2006. In 2006, we drilledone well (0.75 net) in this area. In 2007, we plan to drill 3 to 5 wells (2 to4 net, respectively) in the Mississippi Interior Salt Basin.

# *Michigan*

Asof December 31, 2006, we owned an interest in 658 gross (658 net) acres inMichigan.  We acquired acreage and oneproducing well in south central Michigan as part of the 2003 merger withMiller.  We operate this well whichproduces from the Trenton/Black River formation at approximately 3,000 feet andthis well accounted for

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approximately 1%of our total net production in 2006.  We haveno plans for additional activity in Michigan in 2007 at this time.

# *Southeast New Mexico*

Weestablished a new core area in southeast New Mexico through an alliance withtwo private companies in 2003.  As ofDecember 31, 2006, we owned an interest in 100,015 gross (19,836 net) acres inthis area that we earned through a drilling obligation we fulfilled during 2004and 2005 and through subsequent purchases. The objectives in this area areshallow oil in the Yeso, San Andres, Queen and Grayburg formations, and deepnatural gas in the Atoka and Morrow formations. Additional objectives are theStrawn, Cisco, Wolfcamp and Devonian formations. In 2006, we participated inthe drilling of 16 gross (5.6 net) wells, of which 94% were apparent successes.  Production from wells in the southeast NewMexico area represented approximately 10% of our total net production in2006.  During 2007, we anticipatedrilling 10 to 12 wells (2 to 3 net, respectively) in southeast New Mexico.

# *Arkansas*

Asof December 31, 2006, we owned an interest in 5,448 gross (4,629 net)undeveloped acres in the Fayetteville Shale play in south central Arkansas. In2006, we drilled two wells (0.9 net), both of which were apparently successful,although not yet producing.  During 2007,we anticipate drilling 20 to 24 wells (6 to 8 net, respectively) in this area.

###### **Titleto Properties**

Webelieve we have satisfactory title to all of our producing properties inaccordance with standards generally accepted in the oil and natural gasindustry.  Our properties are subject tocustomary royalty interests, liens incident to operating agreements, liens forcurrent taxes and other burdens, which we believe do not materially interferewith the use of or affect the value of such properties.  As is customary in the industry in the caseof undeveloped properties, little investigation of record title is made at thetime of acquisition (other than a preliminary review of local records).  Detailed investigations, including a title opinionrendered by a licensed attorney, are made before commencement of drillingoperations.

Wehave granted mortgage liens on substantially all of our oil and natural gasproperties in favor of Union Bank of California, as agent, to secure our creditfacility.  These mortgages and the creditfacility contain substantial restrictions and operating covenants that arecustomarily found in loan agreements of this type.  See *ITEM7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OFOPERATIONS* – LIQUIDITY AND CAPITAL RESOURCES – *CREDIT FACILITY”* and Notes 10 and 12 toour consolidated financial statements.

###### **Marketing**

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

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

Thereare a variety of factors which affect the market for oil and natural gas,including the extent of domestic production and imports of oil and natural gas,the proximity and capacity of natural gas pipelines and other transportationfacilities, demand for oil and natural gas, the marketing of competitive fuelsand the effects of state and federal regulations on oil and natural gasproduction and sales.  We have notexperienced any significant

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difficulties inmarketing our oil and natural gas. The oil and natural gas industry alsocompetes with other industries in supplying the energy and fuel requirements ofindustrial, commercial and individual customers.  Where feasible, we use a combination ofmarket-sensitive pricing and forward-fixed pricing.  Forward pricing is utilized to take advantageof anomalies in the futures market.

Dueto the instability of oil and natural gas prices, we may enter into, from timeto time, pricerisk management transactions (e.g., swaps, collars and floors)for a portion of our oil and natural gas production to achieve a morepredictable cash flow, as well as to reduce exposure to pricefluctuations.  While the use of thesearrangements may limit our ability to benefit from increases in the price ofoil and natural gas, it also reduces our potential exposure to adverse pricemovements.  Our price-risk managementarrangements, to the extent we enter into any, apply to only a portion of ourproduction, provide only partial price protection against declines in oil andnatural gas prices and limit our potential gains from future increases inprices.  None of these instruments areused for trading purposes.  All such derivativetransactions provide for financial rather than physical settlement.  On a quarterly basis, our management reviewsall of our price-risk management transaction policies, including volumes,accounting treatment, types of instruments and counterparties. These policiesare implemented 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 ofDirectors continuously monitors our price-risk management policies and trades.  We account for these transactions as hedgingand derivative activities and, accordingly, certain gains and losses areincluded in revenue during the period the transactions occur (see Note 9 to ourconsolidated financial statements and *ITEM 7. “MANAGEMENT’SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS –*CRITICAL ACCOUNTING POLICIESAND ESTIMATES – DERIVATIVES AND HEDGING ACTIVITIES*.”*).

All of these price-riskmanagement transactions are considered derivative instruments and are accountedfor in accordance with SFAS No. 133, *Accountingfor Derivative Instruments and Hedging Activities* (as amended)*.* These derivative instruments are intended to hedgeour price-risk and may be considered hedges for economic purposes, but certainof these transactions may not qualify for cash flow hedge accounting. Allderivative instrument contracts are recorded on the balance sheet at fair valueand the cash flows resulting from settlement of these derivative transactionsare classified in operating activities on the statement of cash flows. For thosederivatives to which mark-to-market accounting treatment is applied, thechanges in fair value are not deferred through other comprehensive income onthe balance sheet. Rather they are immediately recorded in total revenue on thestatement of operations. For those derivatives that are designated and qualifyfor cash flow hedge accounting, the effective portion of the changes in thefair value of the contracts is recorded in other comprehensive income on thebalance sheet and the ineffective portion of the changes in the fair value ofthe contracts is recorded in total revenue on the statement of operations, ineither case as such changes occur. When the hedged production is sold, therealized gains and losses on the contracts are removed from other comprehensiveincome and recorded in revenue. While the contract is outstanding, theunrealized and ineffective gain or loss may increase or decrease untilsettlement of the contract depending on the fair value at the measurementdates.

Duringthe first quarter of 2006, we determined that the cash flow hedge accountingtreatment previously applied to our natural gas derivative contracts should bediscontinued due to projected changes in the 2006 physical production volumeshedged and to give us more flexibility in how we market our physicalproduction. Beginning in the first quarter of 2006, we applied mark-to-marketaccounting treatment to all outstanding derivative contracts, therefore thechanges in fair value are not deferred through other comprehensive income, butrather recorded in revenue immediately as unrealized gains or losses. Goingforward, we will continue to evaluate the terms of new contracts entered intoto determine whether cash flow hedge accounting treatment or mark-to-marketaccounting treatment will be applied. In the past, we used mark-to-marketaccounting treatment for our crude oil derivative contracts and cash flow hedgeaccounting treatment for our natural gas derivative contracts. Therefore,unrealized gains and losses on the change in fair value of natural gasderivative contracts between periods may not be comparable.

Included within totalrevenue for the years ended December 31, 2006, 2005, and 2004 was approximately$9.7 million in net gains, $2.3 million in net losses and $2.5 million in netlosses, respectively, from hedging and derivative activity as shown in thetable below.

13

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| ** **                                                                                                  | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                                  | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                                                  | ** ** | **(in thousands)**                    | ** ** |
| Natural gas  contract settlements (Mcf)                                                                     |       | $                                          | 4,699      |   | $ | (1,230 | ) | $ | (328 | ) |
| Crude oil  contract settlements (Bbl)                                                                       |       | —                                     |       | (1,757 | ) | (881 | ) |
| Hedge premium  reclassification (Mcf)                                                                       |       | —                                     |       | — |   | (686 | ) |
| Mark-to-market  unrealized change in fair value of gas derivative contracts (Mcf)                           |       | 4,686                                      |       | — |   | — |   |
| Mark-to-market  reversal of prior period unrealized change in fair value of oil derivative  contracts (Bbl) |       | (155                                       | )          | 565 |   | — |   |
| Mark-to-market  unrealized change in fair value of oil derivative contracts (Bbl)                           |       | 500                                        |       | 155 |   | (565 | ) |
| Gain (loss) on  hedging and derivatives                                                                     |       | $                                          | 9,730      |   | $ | (2,267 | ) | $ | (2,460 | ) |

 

The table below summarizes our outstanding derivativecontracts reflected on the balance sheet at December 31, 2006 and 2005.
|                           | ** **   | ** **                | ** **   | ** **    | ** **   | ** **   | ** **   | ** **        | ** **   | ** **       | ** **   | **Fair Value of Outstanding Hedging and  Derivative Contracts as of** | ** **   |
|---------------------------|--------------|---------------------------|--------------|---------------|--------------|--------------|--------------|-------------------|--------------|------------------|--------------|---------------------------------------------------------------------------------------------------------------|--------------|
| ** **                | ** **   | ** **                | ** **   | ** **    | ** **   | ** **   | ** **   | **Price**         | ** **   | **Volumes**      | ** **   | **December 31,**                                                                                         | ** **   |
| **Transaction Date** | ** **   | **Transaction Type** | ** **   | **Beginning** | ** **   | **Ending**   | ** **   | **Per Unit** | ** **   | **Per Day** | ** **   | **2006**                                                                                                      | ** **   | **2005** | ** ** |
| ** **                | ** **   | ** **                | ** **   | ** **    | ** **   | ** **   | ** **   | ** **        | ** **   | ** **       | ** **   | **(in thousands)**                                                                                       | ** **   |
| ***Natural  Gas (1):***   | * *     | * *                  |         |          |         |         |         |              |         |             |         |                                                                                                          |         |   |   |
| 08/05                     |         | Natural  Gas Collar       |         | 01/01/2006    |         | 12/31/2006   |         | $7.00-$10.50      |         | 10,000MMbtu      |         | $                                                                                                             | —       |   | $ | (2,498 | ) |
| 08/05                     |         | Natural  Gas Collar       |         | 01/01/2006    |         | 12/31/2006   |         | $7.00-$16.10      |         | 10,000MMbtu      |         | —                                                                                                        |         | (137 | ) |
| 08/06                     |         | Natural Gas Collar        | (3)          | 01/01/2007    |         | 12/31/2007   |         | $7.50-$11.50      |         | 5,000  MMbtu     |         | 2,301                                                                                                         |         | — |   |
| 08/06                     |         | Natural Gas Collar        | (3)          | 01/01/2007    |         | 12/31/2007   |         | $7.50-$12.00      |         | 5,000 MMbtu      |         | 2,385                                                                                                         |         | — |   |
| ***Crude  Oil (2):***     | *** *** | *** ***              | *** *** | *** ***  | *** *** | *** *** | *** *** | *** ***      | *** *** | *** ***     | *** *** | *** ***                                                                                                  | *** *** | *** *** | *** *** |
| 08/05                     |         | Crude  Oil Collar         |         | 01/01/2006    |         | 12/31/2006   |         | $55.00-$80.00     |         | 400Bbl           |         | —                                                                                                        |         | 156 |   |
| 08/06                     |         | Crude Oil Collar          |         | 01/01/2007    |         | 12/31/2007   |         | $70.00-$87.50     |         | 400  Bbl         |         | 1,047                                                                                                         |         | — |   |
| 12/06                     |         | Crude Oil Swap            |         | 01/01/2007    |         | 12/31/2007   |         | $66.00            |         | 600 Bbl          |         | 212                                                                                                           |         | — |   |
| 12/06                     |         | Crude Oil Swap            |         | 01/01/2008    |         | 12/31/2008   |         | $66.00            |         | 1,500 Bbl        |         | (758                                                                                                          | )            | — |   |
|                      |         |                      |         |          |         |         |         |              |         |             |         | $                                                                                                             | 5,187        |   | $ | (2,479 | ) |

 

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(1)                Our currentnatural gas derivative contracts were entered into on a per MMbtu deliveredprice basis, using the Houston Ship Channel Index.  Cashflow hedge accounting, which was applied to these contracts in 2005, wasdiscontinued in 2006. During 2006, mark-to-market accounting treatment wasapplied to these contracts and the change in fair value is reflected in totalrevenue during the year.

(2)                Cash flow hedge accounting is not applied toour crude oil contracts, which were entered into on a per barrel deliveredprice basis, using the West Texas Intermediate Light Sweet Crude Oil Index.Mark-to-market accounting treatment is applied to these contracts and thechange in fair value is reflected in total revenue during the year.

(3)                Subsequent to December 31, 2006, two naturalgas collars covering a portion of our 2007 estimated production were terminatedand replaced with new collars.  The termsof the new contracts are detailed below.

Derivative contracts entered into after December 31,2006 were as follows: 

| **Transaction** | ** ** | ** **                         | ** ** | **Effective Dates** | ** ** | ** ** | ** ** | **Volume Per**          | ** ** |
|-----------------|------------|------------------------------------|------------|--------------------------|------------|------------|------------|------------------------------|------------|
| **Date**        | ** ** | **Transaction Type (1)** | ** ** | **Beginning**            | ** ** | **Ending** | ** ** | **Price Per Unit** | ** ** | **Day** | ** ** |
| 01/07           |       | Natural Gas Collar                 |       | 01/01/08                 |       | 12/31/08   |       | $7.50-$9.00                  |       | 10,000 MMbtu |   |
| 01/07           |       | Natural  Gas Collar                |       | 01/01/08                 |       | 12/31/08   |       | $7.50-$9.02                  |       | 10,000  MMBtu |   |
| 01/07           |       | Natural  Gas Collar                | (2)        | 02/01/07                 |       | 12/31/07   |       | $7.02-$9.00                  |       | 15,000  MMBtu |   |
| 01/07           |       | Natural  Gas Collar                | (2)        | 02/01/07                 |       | 12/31/07   |       | $7.00-$9.00                  |       | 15,000  MMBtu |   |
| 01/07           |       | Natural  Gas Collar                |       | 02/01/07                 |       | 12/31/07   |       | $7.00-$9.00                  |       | 10,000  MMbtu |   |
| 01/07           |       | Natural Gas Collar                 |       | 01/01/08                 |       | 12/31/08   |       | $7.50-$9.00                  |       | 20,000 MMBtu |   |

 

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(1)                Our January 2007 natural gas collars were enteredinto on a per MMbtu delivered price basis, using the NYMEX Natural Gas Index.Mark-to-market accounting treatment will be applied to these contracts and thechange in fair value will be reflected in total revenue.

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(2)                These natural gas collars replaced contractsthat were cancelled subsequent to December 31, 2006.

# **Sales to Major Customers**

Wesold natural gas and crude oil production representing 10% or more of our totalrevenues to the following major customers for the years ended December 31, 2006,2005, and 2004.
|                               | ** ** | **For the Year Ended December 31,** | ** ** |
|-------------------------------|------------|--------------------------------------------------------------|------------|
| **Purchaser**                 | ** ** | **2006**                                                     | ** ** | **2005** | ** ** | **2004** | ** ** |
| Kinder Morgan                 |       | 37                                                           | %          | 29 | % | * |   |
| Chevron  Corporation          |       | 12                                                           | %          | 18 | % | 22 | % |
| Copano Field  Services        |       | 10                                                           | %          | 17 | % | 19 | % |
| Kerr-McGee Oil  & Gas     |       | 10                                                           | %          | * |   | * |   |
| Upstream Energy  Services (1) |       | 3                                                            | %          | 5 | % | 22 | % |

 

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* Zero or lessthan 1%.

(1) UpstreamEnergy Services is an agent that sells our production to other purchasers onour behalf.

NOTE: Amounts disclosed areapproximations and those that are less than 10% are presented for informationand comparison purposes only. These percentages do not consider the effects offinancial derivative instruments.

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

### **Competition**

Wecompete with other oil and natural gas companies in all areas of ouroperations, including the acquisition of exploratory prospects and provenproperties.  Our ability to explore foroil and natural gas reserves and to acquire additional properties in the futurewill be dependent upon our ability to conduct our operations, to evaluate andselect suitable properties and to consummate transactions in this highlycompetitive environment.  We believe thatour technological expertise, our exploration, land, drilling and productioncapabilities and the experience of our management generally enable us tocompete effectively. (See *ITEM 1A. “RISK FACTORS* – We face strongcompetition from larger oil and natural gas companies.”)

###### **INDUSTRYREGULATIONS**

Theavailability of a ready market for oil and natural gas production depends uponnumerous factors beyond our control. These factors include regulation of oil and natural gas production,federal and state regulations governing environmental quality and pollutioncontrol, state limits on allowable rates of production by well or prorationunit, the amount of oil and natural gas available for sale, the availability ofadequate pipeline and other transportation and processing facilities and themarketing of competitive fuels.  Forexample, a productive natural gas well may be “shut-in” because of anoversupply of natural gas or lack of an available natural gas pipeline in theareas in which we may conduct operations. State and federal regulations generally are intended to prevent waste ofoil and natural gas, protect rights to produce oil and natural gas betweenowners in a common reservoir, control the amount of oil and natural gasproduced by assigning allowable rates of production and control contaminationof the environment.  Pipelines aresubject to the jurisdiction of various federal, state and local agencies.  We are also subject to changing and extensivetax laws, the effects of which cannot be predicted.  The following discussion summarizes theregulation of the United States oil and natural gas industry.  We believe that we are in substantialcompliance with the various statutes, rules, regulations and governmentalorders to which our operations may be subject, although there can be noassurance that this is or will remain the case. Moreover, such statutes, rules, regulations and

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government ordersmay be changed or reinterpreted from time to time in response to economic orpolitical conditions, and there can be no assurance that such changes orreinterpretations will not materially adversely affect our results ofoperations and financial condition.  Thefollowing discussion is not intended to constitute a complete discussion of thevarious statutes, rules, regulations and governmental orders to which ouroperations may be subject.

*Regulation of Oil and Natural Gas Exploration andProduction.*  Ouroperations are subject to various types of regulation at the federal, state andlocal 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 operations are also subject to variousconservation laws and regulations.  Theseinclude the regulation of the size of drilling and spacing units or prorationunits and the density of wells that may be drilled in and the unitization orpooling of oil and natural gas properties. In this regard, some states allow the forced pooling or integration oftracts to facilitate exploration while other states rely primarily orexclusively on voluntary pooling of lands and leases.  In areas where pooling is voluntary, it maybe more difficult to form units, and therefore more difficult to develop aproject, if the operator owns less than 100% of the leasehold.  In addition, state conservation laws whichestablish maximum rates of production from oil and natural gas wells, generallyprohibit the venting or flaring of natural gas and impose certain requirementsregarding the ratability of production. The effect of these regulations may limit the amount of oil and naturalgas we can produce from our wells and may limit the number of wells or thelocations at which we can drill.  Theregulatory burden on the oil and natural gas industry increases our costs ofdoing business and, consequently, affects our profitability.  Inasmuch as such laws and regulations arefrequently expanded, amended and interpreted, we are unable to predict thefuture cost or impact of complying with such regulations.

*Regulation of Sales and Transportation of NaturalGas*.   Federallegislation and regulatory controls have historically affected the price ofnatural gas produced by us, and the manner in which such production istransported and marketed.  Under theNatural Gas 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.  EffectiveJanuary 1, 1993, the Natural Gas Wellhead Decontrol Act (the “DecontrolAct”) deregulated natural gas prices for all “first sales” of natural gas,including all sales by us of our own production.  As a result, all of our domestically producednatural gas may now be sold at market prices, subject to the terms of anyprivate contracts that may be in effect. However, the Decontrol Act did not affect the FERC’s jurisdiction overnatural gas transportation.  Under theprovisions of the Energy Policy Act of 2005 (the “2005 Act”), the NGA has beenamended to prohibit any forms of market manipulation in connection with thepurchase or sale of natural gas, and the FERC has issued new regulations toimplement this prohibition. In addition, under the 2005 Act the FERC has beendirected to establish new regulations that are intended to increase natural gaspricing transparency through, among other things, expanded dissemination ofinformation about the availability and prices of gas sold. The 2005 Act alsohas significantly increased the penalties for violations of the NGA.

Ournatural gas sales are affected by intrastate and interstate gas transportationregulation.  Following the Congressionalpassage of the Natural Gas Policy Act of 1978 (“NGPA”), the FERC adopted aseries of regulatory changes that have significantly altered the transportationand marketing of natural gas.  Beginningwith the adoption of Order No. 436, issued in October 1985, the FERC has implementeda series of major restructuring orders that have required pipelines, amongother things, to perform “open access” transportation of gas for others, “unbundle”their sales and transportation functions, and allow shippers to release theirunneeded capacity temporarily and permanently to other shippers. As a result ofthese changes, sellers and buyers of gas have gained direct access to theparticular pipeline services they need and are better able to conduct businesswith a larger number of counterparties. We believe these changes generally have improved our access to marketswhile, at the same time, substantially increasing competition in the naturalgas marketplace.  It remains to be seen,however, what effect the FERC’s other activities will have on access tomarkets, the fostering of competition and the cost of doing business.  We cannot predict what new or differentregulations the FERC and other regulatory agencies may adopt, or what effectsubsequent regulations may have on our activities.  We do not believe that we will be affected byany such new or different regulations materially differently than any otherseller of natural gas with which we compete.

Inthe past, Congress has been very active in the area of gas regulation.  However, as discussed above, the more recenttrend has been in favor of deregulation, or “lighter handed” regulation, andthe promotion of competition in the gas industry.  There regularly are other legislativeproposals pending in the Federal and state legislatures that, if enacted, wouldsignificantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any,might actually be enacted by Congress or the various state legislatures andwhat effect, if any, such

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proposals mighthave on us.  Similarly, and despite thetrend toward federal deregulation of the natural gas industry, we cannotpredict whether or to what extent that trend will continue, or what theultimate effect will be on our sales of gas. Again, we do not believe that we will be affected by any such newlegislative proposals materially differently than any other seller of naturalgas with which we compete.

Weown certain natural gas pipelines that we believe meet the standards the FERChas used to establish a pipeline’s status as a gatherer not subject to FERCjurisdiction under the NGA. These gathering facilities are regulated for safetycompliance by the U.S. Department of Transportation (“DOT”) and/or by stateregulatory agencies. In 2004, the DOT implemented regulations requiring thatpipeline operators implement a pipeline integrity management program that mustat a minimum include an inspection of certain pipeline facilities within tenyears, and at least every seven years thereafter. In addition, beginning in early2006, the DOT’s Pipeline and Hazardous Materials Safety Administrationcommenced a rulemaking proceeding to develop rules that would betterdistinguish onshore gathering lines from production facilities and transmissionlines, and to develop safety requirements better tailored to gathering linerisks. We are not able to predict with certainty the final outcome of thisrulemaking proposal.

Theintrastate pipeline system in Texas is regulated for safety compliance by theDOT and the Texas Railroad Commission. In 2002, the United States Congressenacted the Pipeline Safety Improvement Act of 2002, which contains a number ofprovisions intended to increase pipeline operating safety. The DOT’s finalregulations implementing the 2002 act became effective in February 2004. Amongother provisions, the regulations require that pipeline operators implement apipeline integrity management program that must at a minimum include aninspection of gas transmission pipeline and nonrural gathering facilitieswithin the next ten years, and at least every seven years thereafter. InDecember 2006, Congress enacted the Pipeline Inspection, Protection,Enforcement and Safety Act of 2006, which reauthorizes the programs adoptedunder the 2002 Act, proposes enhancements for state programs to reduceexcavation damage to pipelines, establishes increased federal enforcement ofone-call excavation programs, and establishes a new program for review ofpipeline security plans and critical facility inspections. In addition,beginning in October 2005, the DOT’s Pipeline and Hazardous Materials SafetyAdministration commenced a rulemaking proceeding to develop rules that wouldbetter distinguish onshore gathering lines from production facilities andtransmission lines, and to develop safety requirements better tailored togathering line risks. On March 15, 2006, the DOT revised its regulations todefine more clearly the categories of gathering facilities subject to DOTregulation, establish new safety rules for certain gathering lines in rural areas,revise the current regulations applicable to safety and inspection of gatheringlines in nonrural areas, and adopt new compliance deadlines. We are not able topredict with certainty the final impact of these new rules on the pipelinesthat we will acquire in the Smith acquisition. In addition to safety regulation, state regulation of gatheringfacilities generally includes various environmental, and in some circumstances,nondiscriminatory take requirements, but does not generally entail rate regulation.  Natural gas gathering may receive greaterregulatory rate and service scrutiny at the state level in thepost-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.  The price we receive from the sale of theseproducts may be affected by the cost of transporting the products to market.Much of the transportation is through interstate common carrier pipelines.  Effective as of January 1, 1995, the FERCimplemented regulations generally grandfathering all previously approvedinterstate transportation rates and establishing an indexing system for thoserates by which adjustments are made annually based on the rate of inflation,subject to certain conditions and limitations. The FERC’s regulation of oil transportation rates may tend to increasethe cost of transporting oil and natural gas liquids by interstate pipelines,although the annual adjustments may result in decreased rates in a given year.Every five years, the FERC must examine the relationship between the annualchange in the applicable index and the actual cost changes experienced in theoil pipeline industry.  In March 2006, toimplement the second of the required five-yearly re-determinations, the FERCestablished an upward adjustment in the index to track oil pipeline costchanges. The FERC determined that the Producer Price Index for Finished Goodsplus 1.3 percent (PPI plus 1.3 percent) should be the oil pricing index for thefive-year period beginning July 1, 2006. We are not able at this time to predictthe effects of these regulations or FERC proceedings, if any, on thetransportation costs associated with oil production from our oil producingoperations.

*Environmental Regulations.*  Our operations are subject to numerousfederal, state and local laws and regulations governing the discharge ofmaterials into the environment or otherwise relating to environmentalprotection.  These laws and regulationsmay require the acquisition of a permit before drilling commences, restrict thetypes, quantities and concentration of various substances that can be releasedinto the environment in connection with drilling and production activities,limit or prohibit drilling activities on certain lands within wilderness,

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wetlands and otherprotected areas, require remedial measures to mitigate pollution from formeroperations, such as pit closure and plugging abandoned wells, and imposesubstantial liabilities for pollution resulting from production and drillingoperations.  Public interest in theprotection of the environment has increased dramatically in recent years.  The trend of more expansive and stricterenvironmental legislation and regulations applied to the oil and natural gasindustry could continue, resulting in increased costs of doing business andconsequently affecting profitability.  Tothe extent laws are enacted or other governmental action is taken thatrestricts drilling or imposes more stringent and costly waste handling,disposal and cleanup requirements, our business and prospects could beadversely affected.

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

Wecurrently own or lease numerous properties that for many years have been usedfor the exploration and production of oil and natural gas.  Although we believe that we have used goodoperating and waste disposal practices, prior owners and operators of theseproperties may not have used similar practices, and hydrocarbons or otherwastes may have been disposed of or released on or under the properties ownedor leased by us or on or under locations where such wastes have been taken fordisposal.  In addition, many of theseproperties have been operated by third parties whose treatment and disposal orrelease of hydrocarbons or other wastes was not under our control.  These properties and the wastes disposedthereon may be subject to the Comprehensive Environmental Response,Compensation and Liability Act (“CERCLA”), RCRA and analogous state laws aswell as state laws governing the management of oil and natural gas wastes.  Under such laws, we could be required toremove or remediate previously disposed wastes (including wastes disposed of orreleased by prior owners or operators) or property contamination (includinggroundwater contamination) or to perform remedial plugging operations toprevent future contamination.

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

TheU.S. Congress and various states are currently considering proposed legislationdirected at reducing “greenhouse gas emissions.”  It is not possible at this time to predicthow legislation that may be enacted to address greenhouse gas emissions wouldimpact the oil and gas exploration and production business.  However, future federal laws and regulations,if enacted, could result in increased compliance costs or additional operatingrestrictions and adversely affect our business and prospects.

Federalregulations require certain owners or operators of facilities that store orotherwise handle oil, such as Edge, to prepare and implement spill prevention,control, countermeasure (“SPCC”) and response plans relating to the possibledischarge of oil into surface waters. SPCC plans at our producing properties were developed and implemented in1999.  The Oil Pollution Act of 1990 (“OPA”)contains numerous requirements relating to the prevention of and response tooil spills into waters of the United States. The OPA subjects owners of facilities to strict joint and severalliability for all containment and cleanup costs and certain other damagesarising from a spill, including, but not limited to, the costs of responding toa release of oil to surface waters. Noncompliance with OPA may result in varying civil and criminalpenalties and liabilities.  Ouroperations are also subject to the federal Clean Water Act (“CWA”) andanalogous state laws.  In accordance withthe CWA, the state of Louisiana has issued regulations prohibiting dischargesof produced water in state coastal waters effective July 1, 1997.    Like OPA, the CWA and analogous state lawsrelating to the control of water pollution provide varying civil and criminalpenalties and liabilities for releases of petroleum or its derivatives intosurface waters or into the ground.

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CERCLA, also known as the“Superfund” law, and similar state laws impose liability, without regard tofault or the legality of the original conduct, on certain classes of personsthat are considered to have contributed to the release of a “hazardoussubstance” into the environment.  Thesepersons include the owner or operator of the disposal site or sites where therelease occurred and companies that disposed or arranged for the disposal ofthe hazardous substances found at the site. Persons who are or were responsiblefor releases of hazardous substances under CERCLA may be subject to joint andseveral liability for the costs of cleaning up the hazardous substances thathave been released into the environment, for damages to natural resources andfor the costs of certain health studies, and it is not uncommon for neighboringlandowners and other third parties to file claims for personal injury andproperty damage allegedly caused by the hazardous substances released into theenvironment.

Wealso are subject to a variety of federal, state and local permitting andregistration requirements relating to protection of the environment. Managementbelieves that we are in substantial compliance with current applicableenvironmental laws and regulations and that continued compliance with existingrequirements would not have a material adverse effect on us.

# **OPERATINGHAZARDS AND INSURANCE**

The oil and natural gas business involves a variety ofoperating risks, including the risk of fire, explosion, blow-out, pipe failure,casing collapse, abnormally pressured formations and environmental hazards suchas oil spills, natural gas leaks, ruptures and discharges of toxic gases, theoccurrence of any of which could result in substantial losses to us due toinjury or loss of life, severe damage to or destruction of property, naturalresources and equipment, pollution or other environmental damage, cleanupresponsibilities, regulatory investigation and penalties and suspension ofoperations.

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

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

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

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

·                  the results ofexploration efforts and the acquisition, review and analysis of the seismicdata;

·                  the availabilityof sufficient capital resources to us and the other participants for thedrilling of the prospects;

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

·                  economic andindustry conditions at the time of drilling, including prevailing andanticipated prices for oil and natural gas and the availability of drillingrigs and crews;

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·                  our financialresources 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 DISCUSSION AND ANALYSIS OF FINANCIALCONDITION AND RESULTS OF OPERATIONS* – GENERAL OVERVIEW - INDUSTRY AND ECONOMIC FACTORS*”* and *ITEMS 1 AND 2. “BUSINESSAND PROPERTIES –*CORE AREASOF OPERATION.”

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

Ourrevenue, profitability, cash flow, future growth and ability to borrow funds orobtain additional capital, as well as the carrying value of our properties, aresubstantially dependent upon prevailing prices of oil and natural gas.  Our reserves are predominantly natural gas,therefore changes in natural gas prices may have a particularly large impact onour financial results.  Lower oil andnatural gas prices also may reduce the amount of oil and natural gas that wecan produce economically. Historically, the markets for oil and natural gashave been volatile, and such markets are likely to continue to be volatile inthe future.  Prices for oil and naturalgas are subject to wide fluctuation in response to relatively minor changes inthe supply of and demand for oil and natural gas, market uncertainty and avariety of additional factors that are beyond our control.  These factors include the level of consumerproduct demand, weather conditions, domestic and foreign governmentalregulations, the price and availability of alternative fuels, politicalconditions, the foreign supply of oil and natural gas, the price of foreignimports and overall economic conditions. Declines in oil and natural gas prices may materially adversely affectour financial condition, liquidity, and ability to finance planned capitalexpenditures and results of operations. See *ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS OF OPERATIONS*– RISK MANAGEMENT ACTIVITIES- DERIVATIVES AND HEDGING” and*ITEMS 1 AND 2. “BUSINESS AND PROPERTIES*– OIL AND NATURALGAS RESERVES” and “–* *MARKETING*.”*

Wehave in the past (most recently in the third quarter of 2006) and may in thefuture be required to write down the carrying value of our oil and natural gasproperties when oil and natural gas prices are depressed or unusuallyvolatile.  Whether we will be required totake such a charge will depend on the prices for oil and natural gas at the endof any quarter and the effect of reserve additions or revisions and capitalexpenditures during such quarter.  If awrite down is required, it would result in a charge to earnings, but would notimpact cash flow from operating activities.

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

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

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

Ingeneral, the volume of production from oil and natural gas properties declinesas reserves are depleted, with the rate of decline depending on reservoircharacteristics.  Except to the extent weacquire properties containing proved reserves or conduct successful explorationand development activities, or both, our proved reserves will decline.  Our future oil and natural gas production is,therefore, highly dependent upon our level of success in finding or acquiringadditional reserves. In addition, we 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.

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

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

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

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

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

·                  timing and amount of capital expenditures;

·                  expertise and financial resources;

·                  inclusion of other participants in drilling wells; and

·                  use of technology.

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

Wedepend to a large extent on the services of certain key management personnel,including our executive officers and other key employees, the loss of any ofwhich could have a material adverse effect on our operations.  We do not maintain key-man life insurancewith respect to any of our employees.  Webelieve that our success is also dependent upon our ability to continue toemploy and retain skilled technical personnel. See *ITEM 4.  “SUBMISSIONOF MATTERS TO A VOTE OF SECURITY HOLDERS –*EXECUTIVE OFFICERS OF THEREGISTRANT” and “-SIGNIFICANT EMPLOYEES*.”*

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

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

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

Dueto current industry demands, well service providers and related equipment andpersonnel are in short supply. This is causing escalating prices, delays indrilling and other exploration activities, the possibility of poor servicescoupled with potential damage to downhole reservoirs and personnel injuries.Such pressures will likely increase the actual cost of services, extend thetime to secure such services and add costs for damages due to any accidentssustained from the over use of equipment and inexperienced personnel.

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

Oiland natural gas operations are subject to various federal, state and localgovernment regulations, which may be changed from time to time.  Matters subject to regulation includedischarge permits for drilling operations, drilling bonds, reports concerningoperations, the spacing of wells, unitization and pooling of properties and

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taxation.  From time to time, regulatory agencies haveimposed price controls and limitations on production by restricting the rate offlow of oil and natural gas wells below actual production capacity in order toconserve supplies of oil and natural 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.   In addition, we may be liable forenvironmental damages caused by previous owners of property we purchase orlease.  As a result, we may incursubstantial liabilities to third parties or governmental entities.  We are also subject to changing and extensivetax laws, the effects of which cannot be predicted.  The implementation of new, or themodification of existing, laws or regulations could have a material adverseeffect on us.  See *ITEMS 1**AND 2.* “*BUSINESS ANDPROPERTIES –*INDUSTRYREGULATIONS.”

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

Wehave experienced growth in the past through the expansion of our drillingprogram and, more recently, acquisitions. Thisexpansion was curtailed in 1998 and 1999, but resumed in 2000 and increased insubsequent years. Further expansion is anticipated in 2007 both throughincreased drilling efforts and possible acquisitions.  Any future growth may place a significantstrain on our financial, technical, operational and administrativeresources.  In particular, the Smithacquisition, which was completed in January 2007, has resulted in a significantgrowth in our assets, reserves and revenues and may place a significant strainon our financial, technical, operational and administrative resources. We maynot be able to integrate the operations of the acquired assets withoutincreases in costs, losses in revenues or other difficulties. In addition, wemay not be able to realize the operating efficiencies, synergies, costs savingsor other benefits expected from the Smith acquisition. Any unexpected costs ordelays incurred in connection with the integration could have an adverse effecton our business, results of operations or financial condition.  We currently do not expect to hire anypersonnel associated with Smith. We have added to our staffing levels as aresult of the Smith acquisition,and we intend to hire approximately 5additional employees that we expect will be required to manage the increasedscale of our business.  However, we mayexperience difficulties in finding the additional qualified personnel. In aneffort to stay on schedule with our planned activities in 2007, we intend tosupplement our staff with contract and consultant personnel until we are ableto hire new employees.

Ourability to grow will depend upon a number of factors, including our ability toidentify and acquire new exploratory prospects, our ability to develop existingprospects, our ability to continue to retain and attract skilled personnel, theresults of our drilling program and acquisition efforts, hydrocarbon prices andaccess to capital.   We may not besuccessful in achieving or managing growth and any such failure could have amaterial adverse effect on us.

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

Theoil and gas industry is highly competitive. We encounter competition from oiland natural gas companies in all areas of our operations, including theacquisition of exploratory prospects and productive oil and natural gasproperties. Our competitors range in size from the major integrated oil andnatural gas companies to numerous independent oil and natural gas companies,individuals and drilling and income programs. Many of these competitors are large, well-established companies withsubstantially larger operating staffs and greater capital resources than ours.We may not be able to conduct our operations successfully, evaluate and selectsuitable properties, consummate transactions, and obtain technical, managerialand other professional personnel in this highly competitive environment.  Specifically, these larger competitors may beable to pay more for exploratory prospects, productive oil and natural gasproperties and competent personnel and may be able to define, evaluate, bid forand purchase a greater number of properties and prospects than our financial orhuman resources permit. In addition, such competitors may be able to expendgreater resources on the existing and changing technologies that we believe areand will be increasingly important to attaining success in the industry. Suchcompetitors may also be in a better position to secure oilfield services andequipment on a timely basis or on favorable terms. See*ITEMS 1 AND 2. “BUSINESS AND PROPERTIES*–**COMPETITION.”

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

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

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fromactual results.  Accordingly, reserveestimates may be subject to downward or upward adjustment.  Actual production, revenue and expenditureswith respect to our reserves will likely vary from estimates, and suchvariances may be material. The information regarding discounted future net cashflows included in this report should not be considered as the current marketvalue of the estimated oil and natural gas reserves attributable to ourproperties.  As required by the SEC, theestimated discounted future net cash flows from proved reserves are based onprices and costs as of the date of the estimate, while actual future prices andcosts may be materially higher or lower. Actual future net cash flows also will be affected by factors such asthe amount and timing of actual production, supply and demand for oil andnatural gas, increases or decreases in consumption, and changes in governmentalregulations or taxation.  In addition,the 10% discount factor, which is required by Financial Accounting StandardsBoard in SFAS No. 69, *Disclosures About Oiland Natural Gas Producing Activities* to be used in calculatingdiscounted future net cash flows for reporting purposes, is not necessarily themost appropriate discount factor based on interest rates in effect from time totime and risks associated with us or the oil and natural gas industry ingeneral.  See *ITEMS 1 AND2*. “*BUSINESS AND PROPERTIES –*OIL AND NATURAL GAS RESERVES.”

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

Overthe past few years, increases in commodity prices, in proved reserve amountsand the resultant increase in estimated discounted future net revenue, hasallowed us to increase our available borrowing amounts.  In the future, commodity prices may decline,we may increase our borrowings or our borrowing base may be adjusted downward.  Our credit facility is secured by a pledge ofsubstantially all of our assets and has covenants that limit additionalborrowings, sales of assets and the distributions of cash or properties andthat prohibit the payment of dividends on our common stock and the incurrenceof liens.  The credit facility also requiresthat specified financial ratios be maintained. The restrictions of our credit facility and the difficulty in obtainingadditional debt financing may have adverse consequences on our operations andfinancial results, including our ability to obtain financing for workingcapital, capital expenditures, our drilling program, purchases of newtechnology or other purposes.  Inaddition,  such financing may be on termsunfavorable to us and we may be required to use a substantial portion of ourcash flow to make debt service payments, which will reduce the funds that wouldotherwise be available for operations and future business opportunities.Further, a substantial decrease in our operating cash flow or an increase inour expenses could make it difficult for us to meet debt service requirementsand require us to modify operations and we may become more vulnerable todownturns in our business or the economy generally.

Ourability to obtain and service indebtedness will depend on our futureperformance, including our ability to manage cash flow and working capital,which are in turn subject to a variety of factors beyond our control.  Our business may not generate cash flow at orabove anticipated levels or we may not be able to borrow funds in amountssufficient to enable us to service indebtedness, make anticipated capitalexpenditures or finance our drilling program. If we are unable to generate sufficient cash flow from operations or toborrow sufficient funds in the future to service our debt, we may be requiredto curtail portions of our drilling program, sell assets, reduce capitalexpenditures, refinance all or a portion of our existing debt or obtainadditional financing.  We may not be ableto refinance our debt or obtain additional financing, particularly in view ofcurrent industry conditions, the restrictions on our ability to incur debtunder our existing debt arrangements, and the fact that substantially all ofour assets are currently pledged to secure obligations under our creditfacility.  See*ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONAND RESULTS OF OPERATIONS**–*LIQUIDITY AND CAPITAL RESOURCES” and “–*CREDIT FACILITY.”*

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

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

**Ouracquisition program may be unsuccessful.**

Acquisitions have become increasingly important to ourbusiness strategy in recent years. The successful acquisition ofproducing properties requires an assessment of recoverable reserves, future oiland natural gas prices,

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operating costs,potential environmental and other liabilities and other factors.  Such assessments, even when performed byexperienced personnel, are necessarily inexact and their accuracy inherentlyuncertain. Our review of subject properties will not reveal all existing orpotential problems, deficiencies and capabilities.  We may not always perform inspections onevery well, and may not be able to observe structural and environmental problemseven when we undertake an inspection. Even when problems are identified, the seller may be unwilling or unableto provide effective contractual protection against all or part of suchproblems.  We may be required to assumethe risk of the physical condition of the properties in addition to the riskthat the properties may not perform in accordance with our expectations. We maybe left with no recourse for liabilities and other problems associated withacquisitions that we do not discover prior to the closing date.  Any acquisition of property interests by usmay not be successful and, if unsuccessful, such failure may have an adverseeffect on our future results of operations and financial condition.

**Approximately 36% of the provedreserves associated with the Smith acquisition in January 2007 andapproximately 23% of our proved reserves were undeveloped as of December 31,2006, and those reserves may not ultimately be developed.**

As of December 31, 2006, approximately36% of the proved reserves associated with the Smith acquisition in January2007 and approximately 23% of our proved reserves were undeveloped. Provedundeveloped reserves, by their nature, are less certain than other categoriesof proved reserves. Recovery of undeveloped reserves requires significantcapital expenditures and successful drilling operations and involves greaterrisks. Our reserve data for the properties assumes that to develop our reserveswe will make significant capital expenditures and conduct these operationssuccessfully. Although we have prepared estimates of these natural gas and oilreserves and the costs associated with these reserves in accordance withindustry standards and SEC requirements, the estimated costs may not beaccurate, development may not occur as scheduled and actual results may not beas estimated.

**We do notintend to pay dividends on our common stock and our ability to pay dividends onour common stock is restricted.**

Wehave not historically paid a dividend on our common stock, cash or otherwise, anddo not intend to in the foreseeable future. We are currently restricted from paying dividends on common stock by ourexisting credit facility agreement and, in some circumstances, by the terms ofour Series A preferred stock. Any future dividends also may be restricted byour then-existing debt agreements.  See *ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONAND RESULTS OF OPERATIONS*– LIQUIDITY AND CAPITAL RESOURCES” and Notes 10 and 12 to ourconsolidated financial statements.

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

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

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

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

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

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

None.

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**CERTAINDEFINITIONS**

Thedefinitions set forth below shall apply to the indicated terms as used in thisAnnual Report.  All volumes of naturalgas referred to herein are stated at the legal pressure base of the state orarea where the reserves exist and at 60 degrees Fahrenheit and in mostinstances are rounded to the nearest major multiple.

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

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

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

*Bcf*.  Billion cubic feet.

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

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

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

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

*Development well*.  A well drilled within the proved area of anoil or natural gas reservoir to the depth of a stratigraphic horizon known tobe 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 ornatural gas reserves not classified as proved, to find a new reservoir in afield previously found to be productive of oil or natural gas in anotherreservoir or to extend a known reservoir.

*Farm-in*or*farm-out.*  An agreement whereunder the owner of aworking interest in an oil and natural gas lease assigns the working interestor a portion thereof to another party who desires to drill on the leasedacreage.  Generally, the assignee isrequired to drill one or more wells in order to earn its interest in theacreage.  The assignor usually retains aroyalty and/or reversionary interest in the lease.  The interest received by an assignee is a “farm-in”while the interest transferred by the assignor is a “farm-out.”

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

*Finding costs*.  Costs associated with acquiring anddeveloping proved oil and natural gas reserves which are capitalized by uspursuant to generally accepted accounting principles in the United States,including all costs involved in acquiring acreage, geological and geophysicalwork and the cost of drilling and completing wells, excluding those costsattributable to unproved property.

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

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

*Mcf.*  One thousand cubic feet.

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

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

*MMcf.*  One million cubic feet.

*MMcf/d.*  One million cubic feet per day.

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

*MMcfe/d.*  One million 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*.  Natural gas liquids measured in barrels.

*NRI*or*Net RevenueInterests*.  The share ofproduction after satisfaction of all royalty, overriding royalty, oil paymentsand other nonoperating interests.

*Normally pressured reservoirs.*  Reservoirs with a formation-fluid pressureequivalent to 0.465 PSI per foot of depth from the surface.  For example, if the formation pressure is4,650 PSI at 10,000 feet, then the pressure is considered to be normal.

*Over-pressured reservoirs*.  Reservoirs subject to abnormally highpressure as a result of certain types of subsurface formations.

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

*Present value*.  When used with respect to oil and natural gasreserves, the estimated future gross revenue to be generated from theproduction of proved reserves, net of estimated production and futuredevelopment costs, using prices and costs in effect as of the date indicated,without giving effect to nonproperty-related expenses such as general andadministrative expenses, debt service and future income tax expense or to depletion,depreciation, and amortization, discounted using an annual discount rate of10%.

*Productive well*.  A well that is found to be capable ofproducing hydrocarbons in sufficient quantities such that proceeds from thesale of such production exceeds production 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 andable to produce to market.

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

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

*Proved undeveloped location.*  A site on which a development well can bedrilled consistent with spacing rules for purposes of recovering provedundeveloped reserves.

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*Proved undeveloped reserves*.  Proved reserves that are expected to berecovered from new wells on undrilled acreage or from existing wells where arelatively major expenditure is required for recompletion.

*Recompletion.* The completion for production of an existingwell bore in another formation from that in which the well has been previouslycompleted.

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

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

*3-D seismic*.  Advanced technology method of detectingaccumulations of hydrocarbons identified through a three-dimensional picture ofthe subsurface created by the collection and measurement of the intensity andtiming of sound waves transmitted into the earth as they reflect back to thesurface.

*Undeveloped acreage*.  Lease acreage on which wells have not beendrilled or completed to a point that would permit the production of commercialquantities of oil and natural gas regardless of whether such acreage containsproved reserves.

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

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

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***ITEM3.  LEGAL PROCEEDINGS***

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

**TexasComptroller Audit** - During the second quarter of 2004, wereceived notice that a subsidiary’s franchise tax returns for the State ofTexas would be audited for the tax years 1999 through 2002. After reviewing thedocuments submitted, the agent representing the Office of the Comptroller ofthe State of Texas proposed adjustments to the calculation that would result inan increased franchise tax liability. The agent maintained that transfers by us to our subsidiary, which wereclassified as intercompany loans, should instead be classified as equityinvestments in the subsidiary. The State of Texas originally proposed that thefranchise tax liability of the subsidiaries would be increased by approximately$3.0 million for the four-year period under audit.

Duringthe third quarter of 2006, we and the Comptroller agreed upon a method ofcomputing our franchise tax liability to the State of Texas for the tax years1999 through 2002 that resulted in a total one-time payment of $144,474, pluspenalties of $9,228 which was recorded in 2006. Interest on this settlement of $40,150 was paid in the fourth quarter of2006.

**Wadeand Joyce Montet, et al., v. Edge Petroleum Corp of Texas, et al., consolidatedwith Rolland L. Broussard, et al., v. Edge Petroleum Corp of Texas, et al****.** - This is a consolidated suit, filed in state court in VermilionParish, Louisiana in September 2003. Plaintiffs are mineral/royalty ownersunder the Norcen-Broussard No. 1 and 2 wells, Marg Tex Reservoir C, Sand Unit A(Edge’s old Bayou Vermilion Prospect).  They claim the operator at thetime, Norcen Explorer, now Anadarko, failed to “block squeeze” the sections ofthe No. 2 well, as a prudent operator, according to their allegations, wouldhave done, to protect the gas reservoir from being flooded with water fromadjacent underground formations. Plaintiffs further allege Norcen was negligentin not creating a field-wide unit to protect their interests.  The allegations relate to actions takenbeginning in the early 1990’s. Plaintiffs have named us and other workinginterest owners in the leases as defendants, including Norcen Explorer’ssuccessors in interest, Anadarko. Plaintiffs originally sought unspecifieddamages for lost royalties and damages due to alleged devaluation of theirmineral and property interests, plus interest and attorneys’ fees. In early2005, we filed a motion for summary judgment in the case asserting, among otherdefenses, that:  (i) there has been no breach of contract, (ii) there isno express 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. Alongwith the other defendants, we also filed a special peremptory challenge of nocause of action under the leases and the Louisiana Mineral Code for failure toexhaust administrative remedies and due to lack of a demand. In May and June2005, the court ruled against us on the motion for summary judgment and theperemptory challenges. Of the 18.75% after-payout working interest that wasoriginally reserved in the leases, we owned a 2.8% working interest at the timeof the alleged acts or omissions. On September 6, 2005, we filed a third-partydemand to join the other working interest owners who hold the remainder of the18.75% working interest as third-party defendants in this case. Thesethird-parties consist, for the most part, of partnerships that are directly orindirectly controlled by John Sfondrini, a director of ours, and hold anaggregate 14.7% working interest (the “Sfondrini Partnerships”). VincentAndrews, also a director of ours, owns a minority interest in the corporategeneral partner of one of the partnerships. The Sfondrini Partnerships consistof (1) Edge Group Partnership, a general partnership composed of limitedpartnerships of which Mr. Sfondrini and a company controlled by Mr. Sfondriniare general partners; (2) (A) Edge Option I Limited Partnership, (B) EdgeOption II Limited Partnership and (C) Edge Option III Limited Partnership,limited partnerships of which Mr. Sfondrini and a company controlled by Mr.Sfondrini are general partners; and (3) BV Partners Limited Partnership, alimited partnership of which a company controlled by Messrs. Sfondrini and Andrewsis general partner and of which Mr. Sfondrini is manager (and of which companyMr. Andrews is an officer).  Thesepartnerships were among the third party defendants that we have sought to joinin the case, and these partnerships have for the most part filed answersdenying any liability to us. We participated for our 2.8% share of the wellcosts and revenues for the Broussard No. 2 well, as did the other defendantsfor their share, including the third-party defendant partnerships whoparticipated for 14.7%. We strongly believe the parties should only be liablefor their proportionate share of any damages award should a finding ofliability occur in the case. We intend to vigorously contest the plaintiffs’claims.

Asof the date of this report, it is not possible to determine what, if any, ourultimate exposure might be in this matter. Prior to the settlement describedbelow, plaintiffs had asserted damages, including interest, to be as high as

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$63 million.  The plaintiffs’ expert witness, in his December2005 deposition, offered his theory that plaintiffs’ gross damages are in therange of $19 to $22 million. That number is based on his theory that thealleged failure to block squeeze the well resulted in the under-production ofgas worth $300 million. Plaintiffs’ royalty share of that figure yields the $19to $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 net to our 2.8% share would be in the range of $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. The deposition of a Norcen engineer who prepared thecompletion plan for the Broussard No. 2 well and supervised the completionoperations, taken in April 2006, confirms the testimony of the defense expertsas to why the well was not block squeezed.  The plaintiffs have alsoretained a damages expert who has given a report that the damages in this caseare in the range of $30 million, excluding interest and attorneys’ fees.  Our share of that amount based on the full18.75% would be approximately $5.6 million and net to our 2.8% share would beapproximately $840,000. We participated in mediation of this lawsuit on July18, 2006, but the parties failed to reach an agreement.  In July 2006, the plaintiffs’ attorney sent ademand to the defendants for total damages claimed by plaintiffs, with legalinterest, totaling $63 million.  Ourshare of that amount based on the full 18.75% interest would be approximately$12.2 million and net to our 2.8% interest would be approximately $1.8 million.On July 31, 2006 the Judge granted the defendant groups’ motion for partialsummary judgment dismissing plaintiffs’ tort-based claims. Also on the samedate, the Judge granted the defendant groups’ motion for partial summaryjudgment seeking to deny the plaintiffs an award of attorneys’ fees and also todismiss any claim of plaintiffs that defendants had an obligation to form afield-wide unit.

*Broussard Plaintiff Settlement.*

OnDecember 19, 2006, we, along with the other defendants in this suit, reached asettlement agreement with the Broussard Plaintiffs in full settlement of their72% of the total claims made in this consolidated action.  This settlement was finalized in January2007.  Our share of this settlementtotaled approximately $208,000, which was recorded in December 2006, and theSfondrini Partnerships’ share totaled $1,109,759.  The settlement with the Broussard Plaintiffswas finalized on February 1, 2007, and the defendants and the third-partydefendants including the Sfondrini Partnerships were released from all claimsby the Broussard Plaintiffs.

TheSfondrini Partnerships did not have sufficient cash to fund their respectivefull portion of the settlement. Therefore, in order to facilitate the settlement, we purchased certainoil and gas properties from certain of the Sfondrini Partnerships, with theproceeds of such sale and purchase generally being directed to payment of theBroussard settlement, in full satisfaction of the Sfondrini Partnerships’ shareof such settlement.  The oil and gasproperties that we purchased from the Sfondrini Partnerships and theirrespective purchase prices are as follows:

(1)          100% of each of EdgeGroup Partnership’s, Edge Option I Limited Partnership’s, Edge Option IILimited Partnership’s and Edge Option III Limited Partnership’s interest in theIlse Miller No. 2 Well and leases, Wharton County, Texas, for a total combinedvalue of $51,243.

(2)          100% of each of EdgeGroup Partnership’s, Edge Option I Limited Partnership’s, Edge Option IILimited Partnership’s and Edge Option III Limited Partnership’s interest in theWm Baas 2-16 No. 1 Well and leases, Monroe County, Alabama, for a totalcombined value of $14,407.

(3)          55.953% of Edge GroupPartnership’s interest in certain wells and leases in the Company’s Austin andNita prospects, for a total value of $1,044,109.

Inthe purchase and sale transaction between us and the Sfondrini Partnerships, BVPartners Limited Partnership, whose 2.48% share of the Broussard settlementamount was $186,000 (as determined by us and Mr. Sfondrini on behalf of the BVPartners Limited Partnership), did not sell any assets to us and did not havesufficient funds to satisfy their share of the settlement amount.  In addition, the Edge Option I, II and IIILimited Partnerships did not have sufficient assets to satisfy their respective..34%, .34% and 2.25% shares of the settlement amount, which we and Mr.Sfondrini determined to be $25,750, $25,750 and $169,102, respectively.  The shortfall amounts of Edge Option I, IIand III Limited Partnerships were, net of assets that they sold to us,determined by us and Mr. Sfondrini to be $24,333, $24,333 and $163,276,respectively.  As a result, Edge GroupPartnership sold additional properties (over the amount necessary to fund itsportion of the settlement) to us at fair market value in an amount sufficientto allow it to have proceeds from such sale to fund BV Partners LimitedPartnership’s share of the settlement and the remaining shortfall amounts owedby Edge Option I, II and III.  In return,BV Partners and Edge Option I, II and III contributed all of their interest inthe Bayou Vermilion Prospect leases and the Trahan No. 3 well

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located thereon toEdge Group Partnership.  The fair marketvalue of these interests contributed to Edge Group by BV Partners LimitedPartnership and Edge Option I, II and III were determined by us and Mr.Sfondrini on behalf of such partnerships to be $27,793, $3,847, $3,847 and$25,263, respectively.

Thevaluations of the interests of the Sfondrini Partnerships purchased by us andthe interests contributed to Edge Group Partnership by BV Partners and EdgeOption I, II and III were made at an agreed value, using a PV10 model andassuming $7.50/MMBtu gas and $60/BBl oil, which we believed represented currentpricing levels for oil and gas properties at the time, and were agreed to by usand Mr. Sfondrini, on behalf of the Sfondrini Partnerships.

The trial on theremaining claims, those of the Montet plaintiffs (approximately 28% of theoriginal aggregate claims in the case), is now set for trial beginning August27, 2007.  The Montet plaintiffs’calculation of their alleged damages has not changed.  If the jury were to adopt the plaintiffs’damage figures, the total damages attributable to the Montet plaintiffs couldbe approximately $17.6 million.  Thedefendants’ exposure for an 18.75% share of that number would be approximately$3.31 million.  The exposure for ourapproximate 2.8% share would be approximately $493,000.  If there were a damage award against the defendants,we believe that ultimately we should only be liable for our 2.8% share of anysuch award unless a co-party defendant, including any of the third-partydefendants, cannot satisfy their share of any final judgment or settlementamount or are found not to be liable to us on our third-party demand.  In that event, we could be held responsiblefor more than our 2.8% share.  We believewe have meritorious defenses and intend to continue to vigorously contest thissuit and our third-party demands against the partnerships.  We have not established a reserve withrespect to these claims.

We may have insurancecoverage for all or part of this claim up to the policy limits of $1 millionper occurrence and $2 million in the aggregate. A claim was submitted toMid-Continent Casualty Company, our casualty carrier, who is currentlyproviding a defense under a reservation of rights letter.   However, on July 3, 2006, Mid-Continentfiled a suit for declaratory judgment against us in federal district court inHouston, Texas seeking to determine whether it has a duty to indemnify us andcertain other defendants for this loss under the policies at issue.   Mid-Continent has asked the court to declarethey have no obligation to indemnify us and the third-party defendants based oncertain technical definitions under the policies and the fact that theplaintiffs’ claims are based on alleged breaches of contract. We are bothvigorously defending the declaratory judgment action, and actively seekingindemnity under the policies at issue for our potential liabilities, if any, tothe plaintiffs in the Louisiana actions. We are also pursuing coverage claims under other insurance policies thatcould cover a portion of our share of a loss in this case.

**David Blake, et al. v. Edge Petroleum Corporation**– On September 19, 2005, David Blake and David Blake, Trustee of the David andNita Blake 1992 Children’s Trust filed suit against us in state district courtin Goliad County, Texas alleging breach of contract for failure and refusal totransfer overriding royalty interests to plaintiffs in at least five leases inGoliad County, Texas and failure and refusal to pay monies to Blake pursuant tosuch overriding royalty interests for wells completed on the leases. Theplaintiffs seek relief of (1) specific performance of the alleged agreement,including granting of overriding royalty interests by us to Blake; (2) monetarydamages for failure to grant the overriding royalty interests; (3) exemplarydamages for his claims of business disparagement and slander; (4) monetarydamages for tortuous interference; and (5) attorneys’ fees and court costs.Venue of the case was transferred to Harris County, Texas by agreement of thelitigants.  We have served plaintiffswith discovery and have filed a counterclaim and an amended counterclaimjoining various related entities that are controlled by plaintiffs.  In addition, plaintiffs have filed an amendedcomplaint alleging claims of slander of title and tortuous interference relatedto its alleged right to receive an overriding royalty interest from a thirdparty.  Plaintiffs currently have on filean amended motion for summary judgment, to which we have filed a response.  In addition, we have filed a motion forsummary judgment on the plaintiffs’ case. In December 2006, the court denied our motion for summary judgment.  The court has not ruled on Blake’smotion.  The trial setting in March 2007has been postponed by agreement of the parties and reset to September 15,2007.  Discovery in the case has commencedand is continuing. We have responded aggressively to this lawsuit, and believewe have meritorious defenses and counterclaims.

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

None.

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**ExecutiveOfficers of the Registrant**

Pursuant to Instruction3 to Item 401(b)**of Regulation S-K and GeneralInstruction G (3) to Form 10-K, the following information is included in Part Iof this Form 10-K.

**John W.Elias** has served as the Chief Executive Officer and Chairmanof the Board of the Company since November 1998.  From April 1993 to September 30, 1998, heserved in various senior management positions, including Executive VicePresident, of Seagull Energy Corporation, a company engaged in oil and naturalgas exploration, development and production and pipeline marketing.  Prior to April 1993, Mr. Elias served invarious positions for more than 30 years, including senior management positionswith Amoco Corporation, a major integrated oil and gas company.  Mr. Elias has more than 40 years ofexperience in the oil and natural gas exploration and production business.  He is 66 years old.

# **Michael G. Long** has served as Executive Vice President and ChiefFinancial Officer of the Company since April 2005 and as Senior Vice Presidentand Chief Financial Officer since December 1996, and as Treasurer of theCompany since October 2004.  Mr. Longserved as Vice President-Finance of W&T Offshore, Inc., an oil and naturalgas exploration and production company, from July 1995 to December 1996.  From May 1994 to July 1995, he served as VicePresident of the Southwest Petroleum Division for Chase Manhattan Bank,N.A.  Prior thereto, he served in variouscapacities with First National Bank of Chicago, most recently that of Vice Presidentand Senior Corporate Banker of the Energy and Transportation Department, fromMarch 1992 to May 1994.  Mr. Longreceived a B.A. in Political Science and a M.S. in Economics from theUniversity of Illinois.  Mr. Long is 54years old.

**John O.Tugwell** has served as Chief Operating Officer and ExecutiveVice President since April 2005 and prior to that served as Chief OperatingOfficer and Senior Vice President of Production for the Company since March2004 and prior to that as Vice President of Production since March 1997. Heserved as Senior Petroleum Engineer of the Company’s predecessor corporationsince May 1995.  From 1986 to May 1995,Mr. Tugwell held various reservoir/production engineering positions with ShellOil Company, most recently that of Senior Reservoir Engineer. Mr. Tugwell holdsa B.S. in Petroleum Engineering from Louisiana State University.  Mr. Tugwell is a registered ProfessionalEngineer in the State of Texas.  Mr.Tugwell is 43 years old.

**SignificantEmployees**

**C.W.MacLeod**has served asthe Senior Vice President Business Development and Planning for the Companysince April 2004 and Vice President Business Development and Planning for theCompany since January 2002. From November 1999 to December 2001, he was VicePresident - Investment Banking with Raymond James and Associates, Inc.  From February 1990 to October 1999, Mr.MacLeod was a principal with Kirkpatrick Energy Associates, Inc., whoseprincipal business was merger and acquisition services, capital arrangement andanalytical services for the oil and gas producing industry.  Mr. MacLeod was responsible for originatingcorporate finance and research products for energy clients.  His previous experience includes positions asan independent petroleum geologist, a manager of exploration and production foran independent oil and gas producer and geologic positions with Ladd PetroleumCorporation and Resource Sciences Corporation. Mr. MacLeod graduated from Eastern Michigan University with a B.S. inGeology and earned his M.B.A. from the University of Tulsa.  Mr. MacLeod is a registered professionalgeologist in the State of Wyoming.  He is56 years old.

**HowardCreasey** has served as the Senior Vice President ofExploration since October 2006 and prior to that as the Vice President ofExploration since October 2005.  Before October2005, Mr. Creasey was Chief Geologist for the Company since October 2003. From April of 1999 until October 2003 he served as a Senior StaffGeologist for Devon Energy and its predecessor Ocean Energy.  Priorto April 1999 for 14 years Mr. Creasey 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.Creasey is 51 years old.

**KirstenA. Hink**has served as Vice President and Controller of theCompany since October 1, 2003 and as Controller of the Company since December31, 2000.  Prior to that time she servedas Assistant Controller from June 2000 to December 2000.  Before joining Edge, she served as Controllerof Benz Energy Inc., an oil and gas exploration company, from June 1998 to June2000.  Mrs. Hink received a B.S. inAccounting from Trinity University.  Mrs.Hink is a Certified Public Accountant in the State of Texas.  She is 40 years old.

**Kurt P. Primeaux**has served as Vice President of Production since October 2006, Manager ofProduction Operations from April 2004 to October 2006, and before that, asSenior Petroleum Engineer from August 2003 to April 2004.  Prior to joining the Company, he held similarpositions with Union Oil of California from June 1998 to

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August 2003, most recently that of ResourceManager.  Mr. Primeaux began his careerwith Texaco USA in 1988 and has over 18 years experience in reservoir,drilling, production and operations engineering.  He holds a B.S. degree in PetroleumEngineering from Louisiana State University and an M.S. degree in EnvironmentalEngineering from Tulane University.  Heis 43 years old.

**R. KeithTurner**has served as Vice President of Land for the Companysince September 2006.  Before moving tothe Land Department, Mr. Turner was a Staff Attorney in the Legal Departmentsince 2003.  Prior to joining the Companyin 2003, Mr. Turner served in various capacities with Newfield ExplorationCompany, Fina Oil and Chemical Company and Torch Energy Advisors, Inc.  He received a B.S. in Science from Stephen F.Austin State University and a J.D. degree from South Texas College of Law.  Mr. Turner is 52 years old.

**Robert C.Thomas**has served as Senior Vice President, General Counseland Corporate Secretary since October 2006 and prior to that as Vice President,General Counsel and Corporate Secretary since March 1997.  From February 1991 to March 1997, he servedin similar capacities for the Company’s corporate predecessor.  From 1988 to January 1991, he was associateand acting general counsel for Mesa Limited Partnership in Amarillo,Texas.  Mr. Thomas holds a B.S. degree inFinance and a J.D. degree in Law from the University of Texas at Austin.  He is 53 years old.

33

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##### **PART II**

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

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

Asof March 8, 2007, we estimate there were approximately 236 record holders ofour common stock.  Our common stock islisted on the NASDAQ Global Select Market (“NASDAQ”) and traded under thesymbol “EPEX”.  As of March 8, 2007, wehad 28,383,455 shares outstanding and our closing price on NASDAQ was $11.97per share.  The following table setsforth, for the periods indicated, the high and low closing sales prices for ourcommon stock as listed on NASDAQ.
|                    | ** ** | **Common Stock Prices** | ** ** |
|--------------------|------------|-----------------------------------|------------|
| ** **         | ** ** | **High  ($)**                     | ** ** | **Low  ($)** | ** ** |
| **Calendar  2006** |       |                              |       |   |   |
| First Quarter      |       | 34.65                             |       | 22.89 |   |
| Second Quarter     |       | 26.85                             |       | 16.60 |   |
| Third Quarter      |       | 21.58                             |       | 15.28 |   |
| Fourth Quarter     |       | 20.26                             |       | 15.00 |   |
| ** **         |       |                              |       |   |   |
| **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 |   |

 

***We have never paid a dividend on ourcommon stock, cash or otherwise, and do not intend to in the foreseeablefuture.  In addition, under our currentcredit facility, we are restricted from paying cash dividends on our commonstock.  The payment of future dividends,if any, will be determined by our Board of Directors in light of conditionsthen existing, including our earnings, financial condition, capital requirements,restrictions in financing agreements, business conditions and otherfactors.  See***ITEMS 1A. “RISK FACTORS– We do notintend to pay dividends on our common stock and our ability to pay dividends onour common stock is restricted.”

There were norepurchases of securities during the fourth quarter of 2006.

*Performance Graph*

The following performance graph compares thecumulative total stockholder return on the common stock to the cumulative totalreturn of the Standard & Poor’s 500 Stock Index (“S&P 500 Index”) andan index composed of all publicly traded oil and gas companies identifyingthemselves by primary Standard Industrial Classification (“SIC”) Code 1311(Crude Petroleum and Natural Gas) for the period beginning December 31, 2001and ending December 31, 2006.

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**COMPARE5-YEAR CUMULATIVE TOTAL RETURN**

**AMONGEDGE PETROLEUM CORPORATION, S&P 500 INDEX**

**AND SICCODE 1311 INDEX**

The graph assumes that $100 was invested on December31, 2001 in each of Edge common stock, the S&P 500 Index and the SIC Code1311 companies and assumes that all dividends were reinvested:
|                    | ** ** | **Edge Petroleum** | ** ** | **S&P 500 Index** | ** ** | **SIC Code Index** | ** ** |
|--------------------|------------|-------------------------|------------|---------------------------------|------------|------------------------------|------------|
| December 31,  2001 |       | $                       | 100.00     |                            | $          | 100.00                       |       | $ | 100.00 |   |
| December 31,  2002 |       | $                       | 70.75      |                            | $          | 77.90                        |       | $ | 106.61 |   |
| December 31,  2003 |       | $                       | 190.94     |                            | $          | 100.25                       |       | $ | 171.22 |   |
| December 31,  2004 |       | $                       | 275.09     |                            | $          | 111.15                       |       | $ | 217.51 |   |
| December 31,  2005 |       | $                       | 470.00     |                            | $          | 116.61                       |       | $ | 312.49 |   |
| December 31, 2006  |       | $                       | 344.15     |                            | $          | 135.03                       |       | $ | 406.32 |   |

 

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***ITEM6.  SELECTED FINANCIAL DATA***

***The following table sets forth selectedfinancial data regarding the Company as of and for each of the periodsindicated.  The following data should beread in conjunction with***ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS OF OPERATIONS” and ITEM 8. “FINANCIALSSTATEMENTS AND SUPPLEMENTARY DATA”:
| ** **                                                                            | ** ** | **Year Ended December 31,**                            | ** **  |
|---------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------|-------------|
| ** **                                                                            | ** ** | **2006 (1) (2)**                                            | ** **  | **2005 (3)** | ** ** | **2004 (4)** | ** ** | **2003 (5)** | ** ** | **2002** | ** ** |
| ** **                                                                            | ** ** | **(in thousands, except per share amounts)** | ** **  |
| **Statement of operations:**                                                          | ** ** | ** **                                                            | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil and natural  gas revenue                                                          | ** ** | **$**                                                                 | **129,744** |   | $ | 121,183 |   | $ | 64,505 |   | $ | 33,926 |   | $ | 20,911 |   |
| Operating  expenses:                                                                  |       |                                                                  |        |   |   |   |   |   |   |   |   |
| Oil and natural  gas operating expenses including production and ad valorem taxes     | ** ** | **18,257**                                                            |        | 17,068 |   | 9,309 |   | 5,116 |   | 3,831 |   |
| Depletion,  depreciation, amortization and accretion (5)                              | ** ** | **61,080**                                                            |        | 40,218 |   | 21,928 |   | 13,577 |   | 10,427 |   |
| Impairment of  oil and natural gas properties (6)                                     | ** ** | **96,942**                                                            |        | — |   | — |   | — |   | — |   |
| General and  administrative expenses and bad debt expense                             | ** ** | **13,788**                                                            |        | 12,436 |   | 9,447 |   | 7,132 |   | 5,229 |   |
| Total operating  expenses                                                             | ** ** | **190,067**                                                           |        | 69,722 |   | 40,684 |   | 25,825 |   | 19,487 |   |
| Operating income  (loss)                                                              | ** ** | **(60,323**                                                           | **)**       | 51,461 |   | 23,821 |   | 8,101 |   | 1,424 |   |
| Interest expense  and amortization of deferred loan costs, net of amounts capitalized | ** ** | **(2,665**                                                            | **)**       | (153 | ) | (473 | ) | (679 | ) | (228 | ) |
| Interest income                                                                       | ** ** | **152**                                                               |        | 128 |   | 36 |   | 17 |   | 27 |   |
| Income (loss)  before income taxes and cumulative effect of accounting change         | ** ** | **(62,836**                                                           | **)**       | 51,436 |   | 23,384 |   | 7,439 |   | 1,223 |   |
| Income tax  (expense) benefit                                                         | ** ** | **21,575**                                                            |        | (18,078 | ) | (8,255 | ) | (2,731 | ) | (473 | ) |
| Income (loss)  before cumulative effect of accounting change                          | ** ** | **(41,261**                                                           | **)**       | 33,358 |   | 15,129 |   | 4,708 |   | 750 |   |
| Cumulative  effect of accounting change (5)                                           | ** ** | **—**                                                            |        | — |   | — |   | (358 | ) | — |   |
| Net income  (loss)                                                                    | ** ** | **$**                                                                 | **(41,261** | **)** | $ | 33,358 |   | $ | 15,129 |   | $ | 4,350 |   | $ | 750 |   |
| Basic earnings  (loss) per share:                                                     |       |                                                                  |        |   |   |   |   |   |   |   |   |
| Income (loss)  before cumulative effect of accounting change                          | ** ** | **$**                                                                 | **(2.38**   | **)** | $ | 1.95 |   | $ | 1.16 |   | $ | 0.48 |   | $ | 0.08 |   |
| Cumulative  effect of accounting change                                               | ** ** | **—**                                                            |        | — |   | — |   | (0.03 | ) | — |   |
| Basic earnings  (loss) per share                                                      | ** ** | **$**                                                                 | **(2.38**   | **)** | $ | 1.95 |   | $ | 1.16 |   | $ | 0.45 |   | $ | 0.08 |   |
| Diluted earnings  (loss) per share :                                                  |       |                                                                  |        |   |   |   |   |   |   |   |   |
| Income (loss)  before cumulative effect of accounting change                          | ** ** | **$**                                                                 | **(2.38**   | **)** | $ | 1.87 |   | $ | 1.11 |   | $ | 0.47 |   | $ | 0.08 |   |
| Cumulative  effect of accounting change (5)                                           | ** ** | **—**                                                            |        | — |   | — |   | (0.03 | ) | — |   |
| Diluted earnings  (loss) per share                                                    | ** ** | **$**                                                                 | **(2.38**   | **)** | $ | 1.87 |   | $ | 1.11 |   | $ | 0.44 |   | $ | 0.08 |   |
| Basic weighted  average number of shares outstanding (7)                              | ** ** | **17,368**                                                            |        | 17,122 |   | 13,029 |   | 9,726 |   | 9,384 |   |
| Diluted weighted  average number of shares outstanding (7)                            | ** ** | **17,368**                                                            |        | 17,815 |   | 13,648 |   | 9,988 |   | 9,606 |   |
| **EBITDA Reconciliation (8):**                                                        | ** ** | ** **                                                            | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net income  (loss)                                                                    | ** ** | **$**                                                                 | **(41,261** | **)** | $ | 33,358 |   | $ | 15,129 |   | $ | 4,350 |   | $ | 750 |   |
| Cumulative  effect of accounting change (5)                                           | ** ** | **—**                                                            |        | — |   | — |   | 358 |   | — |   |
| Income tax  expense (benefit)                                                         | ** ** | **(21,575**                                                           | **)**       | 18,078 |   | 8,255 |   | 2,731 |   | 473 |   |
| Interest expense  and amortization of deferred loan costs, net of amounts capitalized | ** ** | **2,665**                                                             |        | 153 |   | 473 |   | 679 |   | 228 |   |
| Interest income                                                                       | ** ** | **(152**                                                              | **)**       | (128 | ) | (36 | ) | (17 | ) | (27 | ) |
| Depletion,  depreciation, amortization and accretion (5)                              | ** ** | **61,080**                                                            |        | 40,218 |   | 21,928 |   | 13,577 |   | 10,427 |   |
| **EBITDA**                                                                            | ** ** | **$**                                                                 | **757**     |   | $ | 91,679 |   | $ | 45,749 |   | $ | 21,678 |   | $ | 11,851 |   |

 

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| ** **                                    | ** ** | **As of December 31,** | ** **   |
|-----------------------------------------------|------------|---------------------------------------|--------------|
| ** **                                    | ** ** | **2006 (1) (2)**            | ** **   | **2005 (3)** | ** ** | **2004 (4)** | ** ** | **2003 (5)** | ** ** | **2002** | ** ** |
| ** **                                    | ** ** | **(in thousands)**               | ** **   |
| **Selected  Cash Flow Data:**                 |       |                                  |         |   |   |   |   |   |   |   |   |
| Net cash  provided by operating activities    | ** ** | **$**                                 | **97,409**   |   | $ | 93,111 |   | $ | 42,270 |   | $ | 23,898 |   | $ | 10,408 |   |
|                                          |       |                                  |         |   |   |   |   |   |   |   |   |
| Net cash used in  investing activities        | ** ** | **$**                                 | **(140,412** | **)** | $ | (167,280 | ) | $ | (89,410 | ) | $ | (28,070 | ) | $ | (19,255 | ) |
| Net cash  provided by financing activities    | ** ** | **$**                                 | **44,418**   |   | $ | 72,568 |   | $ | 48,080 |   | $ | 2,931 |   | $ | 10,623 |   |
| ** **                                    | ** ** | ** **                            | ** **   | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Selected  Balance Sheet Data:**             | ** ** | ** **                            | ** **   | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Working capital  (9)                          | ** ** | **$**                                 | **10,162**   |   | $ | 10,537 |   | $ | 8,957 |   | $ | 948 |   | $ | 3,310 |   |
| Property and  equipment, net                  | ** ** | **289,457**                           |         | 306,456 |   | 165,840 |   | 97,981 |   | 75,682 |   |
| Total assets                                  | ** ** | **321,657**                           |         | 343,380 |   | 190,990 |   | 118,012 |   | 85,576 |   |
| Long-term debt,  including current maturities | ** ** | **129,000**                           |         | 85,000 |   | 20,000 |   | 21,000 |   | 20,500 |   |
| Stockholders’ equity  (7)                | ** ** | **156,052**                           |         | 191,755 |   | 150,467 |   | 82,011 |   | 58,533 |   |

 

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(1)                  As discussed inNote 6 to our consolidated financial statements, we completed one significantproperty acquisition in December 2006 and various other working interestacquisitions throughout the year, which could affect the comparability of ourresults in 2006 to prior periods.

(2)                  As discussed inNote 9 to our consolidated financial statements, in 2006 we discontinued theuse of cash flow hedge accounting on our natural gas contracts.  During2006, mark-to-market accounting treatment was applied to these contracts, whichaffects the comparability of our results in 2006 to prior periods.

(3)                  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, and subsequent periods, toprior periods.

(4)                  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.

(5)                  Asdiscussed in Note 7 to our consolidated financial statements, effective January1, 2003, we changed our method of accounting for asset retirement obligations,which affects the comparability of our results in 2003, and subsequent periods,to prior periods.

(6)                  As discussed in Note 2 to our consolidatedfinancial statements, in the third quarter of 2006 we recorded an impairment ofoil and natural gas properties in the amount of $96.9 million ($63.0 million,net of tax) as a result of our full-cost ceiling test.  The impairment of oil and natural gasproperties was primarily the result of a decline in natural gas prices atSeptember 30, 2006, the date of impairment measurement for the full-costceiling test.  No such impairment wasnecessary in the years 2002 through 2005.

(7)                  Asdiscussed in Note 11 to our consolidated financial statements, we completed apublic offering of our common stock on December 21, 2004 and a significant property acquisition on December 29, 2004,therefore certain of our results in 2004 and subsequent periods are notdirectly comparable to periods prior to 2004.

(8)                  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 not adjusted for the full-cost ceiling test impairment recorded in2006.  EBITDA is a financial measurecommonly used in the oil and natural gas industry, but is not defined underaccounting principles generally accepted in the United States of America (“GAAP”).EBITDA should not be considered in isolation or as a substitute for net income,operating income, cash flows from operating activities or any other measure offinancial performance presented in accordance with GAAP or as a measure of acompany’s profitability or liquidity. Because EBITDA excludes some, but notall, items that affect net income, this measure may vary among companies. TheEBITDA data presented above may not be comparable to a similarly titled measureof other companies. Our management believes that EBITDA is a meaningful measureto investors and provides additional information about our ability to meet ourfuture liquidity requirements for debt service, capital expenditures andworking capital. In addition, management believes that EBITDA is a usefulcomparative measure of operating performance and liquidity.  For example, debt levels, credit ratings and,therefore, the impact of interest expense on earnings vary significantlybetween companies. Similarly, the tax positions of individual companies can varybecause of their differing abilities to take advantage of tax benefits, withthe result that their effective tax rates and tax expense can varyconsiderably. Finally, companies differ in the age and method of acquisition ofproductive assets, and thus the relative costs of those assets, as well as inthe depreciation or depletion (straight-line, accelerated, units of production)method, which can result in considerable variability in depletion, depreciationand amortization expense between companies. Thus, for comparison purposes,management believes that EBITDA can be useful as an objective and comparablemeasure of operating profitability and the contribution of operations toliquidity because it excludes these elements.

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

Wedo not pay cash dividends on our common stock and have not in the periodspresented above; therefore, they are not presented in the selected financialdata.  We expect to pay dividends on our5.75% Series A cumulative convertible perpetual preferred stock issued in ourJanuary 2007 offering.

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

Thefollowing is a review of our financial position and results of operations forthe periods indicated.  Our ConsolidatedFinancial Statements and Supplementary Information and the related notesthereto contain detailed information that should be referred to in conjunctionwith Management’s Discussion and Analysis of Financial Condition and Results ofOperations (“MD&A”).

## ***GENERAL OVERVIEW***

Edge Petroleum Corporation (“Edge”, “we” or the “Company”)is a Houston-based independent energy company that focuses its exploration,development, production, acquisition and marketing activities in selectedonshore basins of the United States. In late 1998, we undertook a top-levelmanagement change and began a shift in strategy from pure exploration, whichfocused more on prospect generation, to our current strategy which focuses on abalanced program of exploration, exploitation and development and acquisitionof oil and gas properties. We generate revenues, income and cash flows byproducing and marketing oil and natural gas produced from our oil and naturalgas properties. We make significant capital expenditures in our exploration,development, and production activities that allow us to continue generatingrevenue, income and cash flows.  We havealso spent considerable efforts on acquisitions, including both corporate andasset acquisitions, which have contributed to our growth in recent years.

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

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

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

·                  **Acquisitions and Divestitures** – informationabout significant changes in our business structure.

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

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

·                  **Results of Operations** – an analysis of ourconsolidated results for the periods presented in our financial statements.

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

·                  **Risk Management Activities**–**Derivatives & Hedging**–****supplementary information regarding ourprice-risk management activities.

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

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

# **INDUSTRY AND ECONOMIC FACTORS**

Inmanaging our business, we must deal with many factors inherent in ourindustry.  First and foremost is thefluctuation of oil and gas prices. Historically, oil and gas markets have been cyclical and volatile, whichmakes future price movements difficult to predict.  While our revenues are a function of bothproduction and prices, wide

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swings incommodity prices have most often had the greatest impact on our results ofoperations. We have little ability to predict those prices or to control themwithout losing some advantage of the upside potential. During 2006, natural gasprices steadily declined from their record highs at the end of 2005.  Crude oil prices spiked to an all-time highin the summer of 2006, but subsequently declined to a price similar to theprice at the end of 2005. Despite these changes in 2006, oil and gas pricesremain at historically high levels.

Ouroperations entail significant complexities. Advanced technologies requiring highly trained personnel are utilized inboth exploration and production.  Evenwhen the technology is properly used, we may still not know conclusively ifhydrocarbons will be present or the rate at which they will be produced.  Exploration is a high-risk activity, oftentimes resulting in no commercially productive reserves being discovered.  Moreover, costs associated with operatingwithin our industry are substantial. The high commodity price environment in2005 led to increased costs in our industry, and in 2006, we saw commodityprices decline while operating costs continued to increase.  These factors, together with increased demandfor rigs, equipment, supplies and services, have made it difficult at times forus to further our growth, and made timely execution of our planned activitiesdifficult.

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.

Theoil and gas industry is highly competitive. We compete with major and diversified energy companies, independent oiland gas businesses and individual operators in exploration, production,marketing and acquisition activities.  Inaddition, the industry as a whole competes with other businesses that supplyenergy to industrial and commercial end users.

Extensivefederal, state and local regulation of the industry significantly affects ouroperations.  In particular, ouractivities are subject to stringent operational and environmental regulations.  These regulations have increased the costs ofplanning, designing, drilling, installing, operating and abandoning oil and gaswells and related facilities.  Theseregulations may become more demanding in the future.

# **APPROACH TO THE BUSINESS**

Profitablegrowth of our business will largely depend upon our ability to successfullyfind and develop new proved reserves of oil and natural gas in a cost-effectivemanner.  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 chosen to seek geologic andgeographic diversification by operating in multiple basins in order to mitigaterisk in our operations. We also attempt to make selected acquisitions of oiland gas properties to augment our growth and provide future drillingopportunities.

Weperiodically hedge our exposure to volatile oil and gas prices on a portion ofour production to reduce price risk. In 2006, we had 53% and 42% of our naturalgas and crude oil production, respectively, hedged.  As of March 9, 2007, we have derivativecontracts in place covering approximately 60% and 72% of our anticipated 2007natural gas and crude oil production, respectively, including the effect of theSmith acquisition which closed in January 2007, but before any otheracquisitions that may occur.

Implementationof our business approach relies on our ability to fund ongoing exploration anddevelopment projects with cash flow provided by operating activities andexternal sources of capital.  Our Boardrecently approved a 2007 capital budget of approximately $140 million. Based oncurrent expectations for production volumes and commodity prices, we expect tofund those capital expenditures from internally generated cash from operatingactivities. We do not typically include acquisitions in our budgeted capitalexpenditures, but expect to fund those with either borrowings under our creditfacility, proceeds from offerings of common stock or other securities under ourshelf registration statement or other sources.

For2006, we reported a 5% increase in annual production volumes over the 2005period. We also replaced 97% of our total 2006 production (see *ITEMS 1 AND 2. “BUSINESS AND PROPERTIES*– OILAND NATURAL GAS RESERVE REPLACEMENT”). At December 31, 2006, our net proved reserves were 102.1 Bcfe, of whichapproximately 77% were developed.  Inaddition, in January 2007, we acquired certain oil and gas properties fromSmith Production Inc., as discussed below in *“ACQUISITIONSAND DIVESTITURES - Acquisitions.”* Following the completion of our two recent public offerings thatresulted in net proceeds of approximately $276.7 million, we believe we are ina strong financial position.  We haveunused borrowing capacity of $85.0 million as of March 9,

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2007.  Operationally and financially, we believe weare well positioned to continue the execution of our business strategy during2007.

**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 reservesand production 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 neither budgetednor allocated.  Specific timing and sizeof acquisitions cannot be predicted. Although we consider a wide variety ofacquisitions, a significant part of our growth strategy is expected to befocused toward producing property acquisitions, which we believe have exploitablepotential. Because of our financial flexibility, we are positioned to takeadvantage 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 January 31, 2007, wecompleted the purchase. of certain oil and natural gas properties located in 13counties in south and southeast Texas and other assets from Smith ProductionInc.  We paid approximately $389.8million for these assets.  In total, theSmith assets include approximately 150 gross producing wells (74 net) and anownership interest in approximately 17,000 gross (12,250 net) developed acresand 56,000 gross (16,000 net) undeveloped acres of leasehold, all as ofDecember 31, 2006.  In addition to theproperties and related acreage, we acquired from Smith certain gathering facilitiesand ownership of approximately 13 miles of natural gas gathering pipelines andrelated infrastructure serving certain producing assets in southeast Texas. Thepipeline system transports our natural gas as well as third-party naturalgas.  We also acquired 25% of Smith’soption and leasehold rights in an approximate 95 square mile 3-D explorationarea with approximately 30,000 gross acres of leases and options located in theMission project area in Hidalgo County in south Texas, with a primary focus onthe Vicksburg formation.  We acquired a12.5% working interest in an approximate 160 square mile 3-D exploration areawith approximately 55,000 gross acres of leases and options located in theYates Ranch/Hostetter project area in McMullen and Duval Counties in southTexas. The 160 mile 3-D area increases our exposure to the Middle and DeepWilcox trend. Furthermore, this venture allows us to participate in a proposedadditional 3-D shoot covering approximately 120 square miles near theYates Ranch within the Wilcox trend. We also acquired 25% of Smith’s option andleasehold rights in an approximate 105 square mile 3-D exploration area withapproximately 60,000 gross acres of leases and options in Newton County insoutheast Texas and Beauregard Parish in Louisiana with a focus on prospects inthe Frio, Yegua and Wilcox formations at depths ranging between 4,000 and10,000 feet.  We financed the Smithacquisition through concurrent public offerings of 10.925 million shares of ourcommon stock and 2.875 million shares of our Series A preferred stock, alongwith borrowings under a new revolving credit facility.

On December 28, 2006, wecompleted an acquisition of certain working interests in the Chapman RanchField in Nueces County, Texas from Kerr-McGee, a wholly-owned subsidiary ofAnadarko Petroleum Corporation.  In late2005, we acquired non-operated working interests ranging from 44% to 50% inseveral producing wells in this field, as discussed below.  In the Kerr-McGee acquisition, we acquired anadditional 44% to 50% working interest in the same wells in the field andacquired two additional wells, bringing our working interests in those ChapmanRanch properties, including a total of nine producing wells, to 88% to100%.  The base purchase price of theacquisition was $26.0 million.  Thepurchase price was preliminarily adjusted at closing to approximately $25million (including a previously paid deposit of $2.6 million) as a result ofadjustments to the purchase price for the results of operations between theDecember 1, 2006 effective date and the December 28, 2006 closing date, andother purchase price adjustments.  Theremay be post-closing adjustments to the purchase price for results of operationsbetween the effective date and closing date as further information becomesavailable.  We financed the purchaseprice of the Kerr-McGee acquisition through $24.0 million in borrowings underour credit facility, the borrowing base of which was increased in connectionwith this transaction (see Note 10 to our consolidated financial statements).

On September 21, 2005, weacquired (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 south Texas and (ii) additionalworking interests in the same field owned by two other private

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companies for an aggregate cash purchase price ofapproximately $74.9 million (of which $46.9 million was attributable to thestock purchase and $28.0 million was attributable to the working interest assetpurchase). We allocated approximately $17.5 million of the total purchase priceto the unproved property category. The properties acquired from these entitiesare located in Nueces County, Texas and consisted of six producing wells, one wellundergoing completion operations, and one well shut in for evaluation, as wellas an ownership interest in approximately 1,300 net acres of developed andundeveloped leasehold.  We financed theacquisitions through borrowings under our then-existing credit facility, theborrowing base of which was increased in connection with the acquisitions andother activities after the last redetermination.

On October 13, 2005, weconsummated the Chapman Ranch Field asset acquisition for a final purchaseprice of $28.0 million. On November 30, 2005, we consummated the Cinco stockpurchase for a final purchase price of $46.9 million.

On December 29, 2004, weacquired oil and natural gas properties located in south Texas from ContangoOil & Gas Company (“Contango”) for a final purchase price of $40.1million.  We financed the acquisitionwith proceeds from a public offering of our common stock under our shelfregistration (see Note 11 to our consolidated financial statements). The propertiesacquired consisted of 39 non-operated producing wells with working interestsranging from approximately 41% to 75% and net revenue interests ranging from29% to 56%. These properties, located primarily in Jim Hogg County, Texas andproducing primarily from the Queen City formation, are in a geographic areathat has been one of our most active and successful areas of focus in recentyears. In addition to estimated proved reserves, our technical team alsoidentified a substantial number of additional drilling locations on undevelopedacreage for which we realized much of the exploitable potential in 2005 and2006.  We believe this area to be acontinued target of exploitable potential for us in future years.

*Divestitures -*We regularlyreview our asset base for the purpose of identifying non-core assets, thedisposition of which would increase capital resources available for otheractivities and create organizational and operational efficiencies. While wegenerally do not dispose of assets solely for the purpose of reducing debt,such dispositions can have the result of furthering our objective of financialflexibility through reduced debt levels. During the first half of 2006, we soldour Buckeye properties in Live Oak County, Texas for $627,645.  During 2005, we had no divestitures. During2004, our net proceeds from asset divestitures of $60,000 were primarilyderived from the sale of certain oil and gas properties and equipment in Texas,Mississippi and Louisiana.

**OUTLOOK**

·                  We successfullycompleted one significant acquisition during 2006, as well as a large,transforming acquisition in the first quarter of 2007, both of which addedvaluable reserves in our core areas in Texas. We also completed smaller workinginterest acquisitions in 2006.  We expectto continue to spend considerable effort in 2007 on acquisitions, as we seek tofurther our growth.

·                  We expect to drill between 80 and 90 wells (37 and42 net, respectively) in 2007 and we estimate capital spending for the year tobe approximately $140 million. Our ability to materially increase thenumber of wells to be drilled is heavily dependent upon the timely access tooilfield services, particularly drilling rigs. The shortage of available rigs in 2006 delayed the drilling of severalwells, slowing growth in our production for the year.

·                  Drillingactivities in the Fayetteville Shale play were initiated during the secondquarter of 2006 and we expect that activity to continue into 2007.

·                  In order tomanage our realized growth in 2006 and our anticipated growth for the nextseveral years, we increased our headcount from 62 employees as of December 31,2005 to 68 employees as of December 31, 2006, resulting in increased G&Acosts for 2006. We have added and expect to continue to add to our staff levelsagain in 2007 both as a result of recent growth and anticipated future growth.

·                  To help protectagainst the possibility of downward commodity price movements and lost revenue,we have several derivatives in place to hedge a portion of our expected naturalgas and crude oil production streams for 2007 and 2008. While there was no cashimpact from our oil derivatives contracts, our gas derivatives contractscontributed $4.7 million to our cash flows in 2006. We discontinued cash flowhedge accounting treatment on our natural gas collars, and thus all of ourderivative transactions are now accounted for using mark-to-market accountingtreatment (see Note 9 to our consolidated financial statements).

·                  Werecorded a $96.9 million ($63.0 million, net of tax) non-cash impairmentrelating to our oil and natural gas properties during the third quarter of 2006resulting from our full-cost ceiling test. Natural gas prices

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fell below $5.00 perMMBtu at September 30, 2006, but subsequently rose above $6.00 per MMBtu afterthe third quarter end, which we believe would have allowed us to avoid theimpairment if, as would have been allowed under applicable accountingguidelines, we had elected to use such subsequent prices in determining thecalculation of our ceiling test at September 30, 2006. However, oil and naturalgas prices are expected to continue to be volatile in the future.  The benefit of the write-down is that it isexpected to decrease future depletion expense and we believe that it will moreappropriately state our capitalized costs.

Ouroutlook and the expected results described above are both subject to changebased upon factors that include, but are not limited to, drilling results,commodity prices, access to capital, the acquisitions market and factorsreferred to in “FORWARD LOOKING INFORMATION.”

**CRITICAL ACCOUNTINGPOLICIES AND ESTIMATES**

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

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

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

All other significantaccounting policies that we employ are presented in the notes to theconsolidated financial statements. The following discussion presentsinformation about the nature of our most critical accounting estimates, ourassumptions or approach used and the effects of hypothetical changes in thematerial assumptions used to develop each estimate.

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

*Assumptions/ApproachUsed:*Units-of-production method to amortize our oil andnatural gas properties - The quantity of reserves could significantlyimpact our depletion expense. Any reduction in proved reserves without acorresponding reduction in capitalized costs will increase the depletion 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 test. The ceiling is the discounted present value of ourestimated total proved reserves adjusted for taxes and the impact of qualifyinghedges on pricing, using a 10% discount rate. To the extent that ourcapitalized costs (net of accumulated depletion and deferred taxes) exceed theceiling, the excess must be written off to expense. Once incurred, thisimpairment of oil and gas properties is not reversible at a later date even ifoil and gas prices increase. A ceiling test impairment could result in a significantloss for a reporting period; however, future depletion expense would becorrespondingly reduced. During the year ended December 31, 2006, we recorded aceiling test impairment of $96.9 million ($63.0 million, net of tax).  No such impairment was required in the yearsended December 31, 2005 and 2004. The ceiling test calculation dictates thatprices and costs in effect as of the last day of the period are to be used incalculating the discounted present value of our estimated total proved reserves.  Oil and natural gas prices used in thereserve valuation at December 31, 2006 were $61.06 per barrel and $5.62 perMMbtu.

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*Effectif different assumptions used:*Units-of-production method to amortizeour oil and natural gas properties - A 10% increase or decrease in reserveswould have decreased or increased, respectively, our depletion expense for theyear by approximately 10%.

“Ceiling” Test - The mostlikely factor to contribute to a ceiling test impairment is the price used tocalculate the reserve limitation threshold. A significant reduction in pricesat a measurement date could trigger a full-cost ceiling impairment. Such areduction from June 30, 2006 to September 30, 2006 was primarily responsiblefor our impairment in the third quarter of 2006.  Subsequent to September 30, 2006, quotedmarket prices for natural gas increased such that we believe we would haveavoided a write down if, as would have been allowed under applicable accountingguidelines, we had elected to use such subsequent prices in calculating ourceiling test at September 30, 2006.  Wehad a cushion (i.e. the excess of the ceiling over our capitalized costs) of$31.9 million, net of tax, at December 31, 2006.  A 10% increase or decrease in prices usedwould have increased or decreased, respectively, our cushion by approximately78%. Our hedging program would serve to mitigate some of the economic impact ofany price decline. However, since we no longer apply cash flow hedge accountingto our derivative contracts, our hedging program does not impact the ceilingtest. Had we applied cash flow hedge accounting to our outstanding derivativecontracts, the cushion at December 31, 2006 would have increased byapproximately $11.1 million. Another likely factor to contribute to a ceilingtest impairment is a revised estimate of reserve volume. A 10% increase ordecrease in reserve volume would have increased or decreased, respectively, ourcushion at December 31, 2006 by approximately 53%, net of tax.  As noted above, we used pricing and costs asof the last day of the period to determine our ceiling test.  Should commodity prices decreasesignificantly in 2007, the possibility of a ceiling test impairment at a futuredate exists.  Also, the effects of theSmith acquisition in 2007 could increase the possibility that we will berequired to record a ceiling test impairment, particularly if commodity pricesdecline below the effective levels paid for in the Smith acquisition.

*Natureof Critical Estimate Item:*Unproved Property Impairment****- We have elected to use the full-cost method to account forour oil and gas activities. Investments in unproved properties are notamortized until proved reserves associated with the prospects can be determinedor until impairment occurs.  Unprovedproperties are evaluated quarterly for impairment on a property-by-propertybasis.  If the results of an assessmentindicate that an unproved property is impaired, the amount of impairment isadded to the proved oil and natural gas property costs to be amortized.

*Assumptions/ApproachUsed:*At December 31, 2006, we had $57.6 million allocated tounproved property. This allocation is based on our estimation of whether theproperty has potential attributable reserves. Therefore, our assessment of thepotential reserves will determine whether costs are moved from the unprovedcategory to the full-cost pool for depletion or whether an impairment is taken.

*Effectif different assumptions used:* A 10% increase or decrease in theunproved property balance (i.e. transfer to full-cost pool) would havedecreased or increased, respectively, our depletion expense by approximately 2%for the year ended December 31, 2006.

*Natureof Critical Estimate Item:*Asset Retirement Obligations**-**We have certain obligations to removetangible equipment and restore land at the end of oil and gas productionoperations.  Our removal and restorationobligations are primarily associated with plugging and abandoning wells. Priorto the adoption of Statement of Financial Accounting Standards (“SFAS”) No. 143,*Accounting for Asset Retirement Obligations*,the costs associated with this activity were capitalized to the full-cost pooland charged to income through depletion. SFAS No. 143 significantly changed themethod of accruing for costs an entity is legally obligated to incur related tothe retirement of fixed assets (“asset retirement obligations” or “ARO”).  Primarily, SFAS No. 143 requires us toestimate asset retirement costs for all of our assets, adjust those costs forinflation to 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. Weaccrete 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

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is performed using the same methodologyof taking 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 the future asset removal costs is difficultand requires management to make estimates and judgments because most of theremoval obligations are many years in the future, and contracts and regulationsoften have vague descriptions of what constitutes removal.  Asset removal technologies and costs areconstantly changing, as are regulatory, political, environmental, safety andpublic relations considerations. Inherent in the estimate of the present valuecalculation of our AROs are numerous assumptions and judgments including theultimate settlement amounts, inflation factors,credit-adjusted-risk-free-rates, timing of settlement, and changes in thelegal, regulatory, environmental and political environments.

*Effectif different assumptions used:* Since there are so many variables inestimating AROs, we attempt to limit the impact of management’s judgment oncertain of these variables by using input of qualified third parties. We engageindependent engineering firms to evaluate our properties annually. We use theremaining estimated useful life from the year-end reserve reports by ourindependent reserve engineers in estimating when abandonment could be expectedfor each property. We utilize a three-year average rate for inflation to diminishany significant volatility that may be present in the short term. We expect tosee our calculations impacted significantly if interest rates are volatile, asthe credit-adjusted-risk-free rate is one of the variables used on a quarterlybasis. We have developed a standard cost estimate based on historical costs,industry quotes and depth of wells. Unless we expect a well’s plugging to besignificantly different than a normal abandonment, we use this estimate. Theresulting estimate, after application of a discount factor and some significantcalculations, could differ from actual results, despite all our efforts to makean accurate estimate.

*Natureof Critical Estimate Item:*Income Taxes**-**In accordance with the accounting for income taxes underSFAS No. 109, *Accounting for Income Taxes,*we have recorded a deferred tax asset and liability to account for the expectedfuture tax benefits and consequences of events that have been recognized in ourfinancial statements and our tax returns. There are several items that resultin deferred tax asset and liability impact to the balance sheet, but thelargest of which is the impact of net operating loss (“NOL”) carryforwards. Weroutinely assess our ability to use all of our NOL carryforwards that resultfrom substantial income tax deductions, prior year losses and acquisitions. Weconsider future taxable income in making such assessments.  If we conclude that it is more likely thannot that some portion or all of the deferred tax assets will not be realizedunder accounting standards, it is reduced by a valuation allowance.

*Assumptions/ApproachUsed:*Numerous judgments and assumptions are inherent in thedetermination of future taxable income, including factors such as futureoperating conditions (particularly as related to prevailing oil and natural gasprices). We were required to makealternative minimum tax payments for 2006 of $94,100 and for 2005 of $327,400 ,but no alternative minimum tax payments were made in 2004.

*Effectif different assumptions used:* We have engaged an independentpublic accounting firm to assist us in applying the numerous and complicatedtax law requirements. However, despite our attempt to make an accurateestimate, the ultimate utilization of our NOL carryforwards is highly dependentupon our actual production and the realization of taxable income in futureperiods. If we estimate that some or all of our NOL carryforwards are morelikely than not going to expire or otherwise not be utilized to reduce futuretax, we would record a valuation allowance to remove the benefit of those NOLcarryforwards from our financial statements.

*Natureof Critical Estimate Item:*Derivative and HedgingActivities**-**Due to theinstability of oil and natural gas prices, we may enter into, from time totime, price-risk management transactions (e.g., swaps, collars and floors) fora portion of our oil and natural gas production to achieve a more predictablerevenue, as well as to reduce exposure from commodity price fluctuations. Whileall of these transactions are economic hedges

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of price risk, different accounting treatment mayapply depending on if they qualify for cash flow hedge accounting. Inaccordance with SFAS No. 133, *Accounting forDerivative Instruments and Hedging Activities (as amended),*alltransactions are recorded on the balance sheet at fair value.  See*ITEMS1 AND 2. “BUSINESS AND PROPERTIES**–*MARKETING.”

Hedge Contracts - We formally assess, both at thehedge’s inception and on an ongoing basis, whether the derivatives that areused for hedging are expected to be highly effective in offsetting changes incash flows of the hedged transactions. The ongoing measurement of effectiveness determines whether the changein fair value is deferred through other comprehensive income (“OCI”) on thebalance sheet or recorded immediately in revenue on the income statement. Theeffective portion of the changes in the fair value of hedge contracts isrecorded initially in OCI. When the hedged production is sold, the realizedgains and losses on the hedge contracts are removed from OCI and recorded inrevenue. Ineffective portions of the changes in the fair value of the hedgecontracts are recognized in revenue as they occur. The cash flows resultingfrom settlement of these hedge transactions are included in cash flows fromoperating activities on the statement of cash flows.  While the hedge contract is outstanding, thefair value may increase or decrease until settlement of the contract. In theevent it is determined that the use of a particular derivative may not be orhas ceased to be effective in pursuing a hedging strategy, hedge accounting isdiscontinued prospectively. During the first quarter of 2006, we discontinuedcash flow hedge accounting treatment applied to our natural gas contracts dueto projected changes in the 2006 physical production volumes hedged and to giveus flexibility in how we market our physical production. Therefore, allcontracts are utilizing mark-to-market accounting treatment rather than cashflow hedge accounting treatment at December 31, 2006, as discussed below.

Derivative Contracts - For transactionsaccounted for using mark-to-market accounting treatment, the change in the fairvalue of the derivative contract is reflected in revenue immediately, and notdeferred through OCI, and there is no measurement of effectiveness.

*Assumptions/ApproachUsed:*Estimating the fair values of derivative instrumentsrequires complex calculations, including the use of a discounted cash flowtechnique, estimates of risk and volatility, and subjective judgment inselecting an appropriate discount rate. In addition, the calculations usefuture market commodity prices, which although posted for trading purposes, aremerely the market consensus of forecasted price trends. The results of the fairvalue calculations cannot be expected to represent exactly the fair value ofour commodity hedges. We currently obtain the fair value of our positions fromour counterparties. Our practice of relying on our counterparties who are morespecialized and knowledgeable in preparing these complex calculations reducesour management’s input and approximates the fair value of the contracts, as thefair value obtained from our counterparties would be the cost to us toterminate a contract at that point in time. Due to the fact that we applymark-to-market accounting treatment, the offset to the balance sheet asset orliability, or the change in fair value of the contracts, is included in revenueon the income statement rather than in OCI on the balance sheet.

*Effectif different assumptions used:* At December 31, 2006, a 10%change in the commodity price per unit, as long as the price is either abovethe ceiling or below the floor price, would cause the fair value total of ourderivative financial instruments to increase or decrease by approximately $0.6million. Had we applied cash flow hedge accounting treatment to all of ourderivative contracts outstanding at December 31, 2006, our net loss for theyear would have been reduced to $33.3 million.

# **RESULTS OF OPERATIONS**

This section includesdiscussion of our 2006, 2005 and 2004 results of operations.  We are an independent energy company engagedin the exploration, development, acquisition and production of oil and naturalgas.  Our resources and assets aremanaged and our results reported as one operating segment.  We conduct our operations primarily along theonshore United States Gulf Coast, with our primary emphasis in south Texas,Mississippi, Louisiana and southeast New Mexico.

**Revenue and Production**

Ourprimary source of production and revenue is natural gas. For the years endedDecember 31, 2006, 2005 and 2004, our product mix contributed the followingpercentages of revenues and production:

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|                      | ** ** | **REVENUES **(1) | ** ** |
|----------------------|------------|-----------------------|------------|
| ** **           | ** ** | **2006**              | ** ** | **2005** | ** ** | **2004** | ** ** |
| Natural gas          |       | 79                    | %          | 82 | % | 82 | % |
| Natural gas  liquids |       | 4                     | %          | 5 | % | 7 | % |
| Crude oil            |       | 17                    | %          | 13 | % | 11 | % |
|                 |       |                  |       |   |   |   |   |
| Total                |       | 100                   | %          | 100 | % | 100 | % |

 

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(1)          Includeseffect of hedging and derivative transactions.
|                      | ** ** | **PRODUCTION VOLUMES (MCFE)** | ** ** |
|----------------------|------------|-----------------------------------------|------------|
| ** **           | ** ** | **2006**                                | ** ** | **2005** | ** ** | **2004** | ** ** |
| Natural gas          |       | 80                                      | %          | 77 | % | 75 | % |
| Natural gas  liquids |       | 8                                       | %          | 11 | % | 14 | % |
| Crude oil            |       | 12                                      | %          | 12 | % | 11 | % |
|                 |       |                                    |       |   |   |   |   |
| Total                |       | 100                                     | %          | 100 | % | 100 | % |

 

Our revenue is sensitive tochanges in prices received for our products. A substantial portion of our production is sold at prevailing marketprices, which fluctuate in response to many factors that are outside of ourcontrol.  Imbalances in the supply anddemand for oil and natural gas can have a dramatic effect on the prices wereceive for our production.  Politicalinstability and availability of alternative fuels could impact worldwidesupply, while the economy, weather and other factors outside of our controlcould impact demand.

The following table summarizes production volumes,average sales prices and operating revenue for our oil and natural gasoperations for the periods indicated.
| ** **                                    | ** ** | **For the Year Ended December 31,**               | ** ** | **% Increase  (Decrease)** | ** ** |
|-----------------------------------------------|------------|----------------------------------------------------------------------------|------------|---------------------------------|------------|
| ** **                                    | ** ** | **2006**                                                                   | ** ** | **2005**                        | ** ** | **2004** | ** ** | **06 vs.   05** | ** ** | **05 vs.   04** | ** ** |
| ** **                                    | ** ** | **(in thousands, except prices and percentages)** | ** ** |
| **Production  Volumes:**                      |       |                                                                       |       |                            |       |   |   |   |   |   |   |
| Natural gas (Mcf)                             |       | 13,850                                                                     |       | 12,597                          |       | 9,148 |   | 10 | % | 38 | % |
| Natural gas  liquids (Bbls)                   |       | 222                                                                        |       | 308                             |       | 276 |   | (28 | )% | 11 | % |
| Oil and  condensate (Bbls)                    |       | 345                                                                        |       | 324                             |       | 215 |   | 6 | % | 51 | % |
| Natural gas  equivalent (Mcfe)                |       | 17,251                                                                     |       | 16,384                          |       | 12,093 |   | 5 | % | 35 | % |
| **Average  Sales Price (1):**                 | ** ** | ** **                                                                 | ** ** | ** **                      | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Natural gas ($ per  Mcf)(2)              |       | $                                                                          | 6.68       |                            | $          | 7.97 |   | $ | 5.91 |   | (16 | )% | 35 | % |
| Natural gas  liquids ($ per Bbl)         |       | 25.52                                                                      |       | 18.45                           |       | 15.83 |   | 38 | % | 17 | % |
| Oil and  condensate ($ per Bbl) (2)      |       | 63.10                                                                      |       | 53.57                           |       | 39.77 |   | 18 | % | 35 | % |
| Natural gas  equivalent ($ per Mcfe) (3) |       | 7.52                                                                       |       | 7.40                            |       | 5.33 |   | 2 | % | 39 | % |
| **Operating  Revenue:**                       | ** ** | ** **                                                                 | ** ** | ** **                      | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Natural gas (2)                               |       | $                                                                          | 92,582     |                            | $          | 100,437 |   | $ | 54,057 |   | (8 | )% | 86 | % |
| Natural gas  liquids                          |       | 5,665                                                                      |       | 5,677                           |       | 4,373 |   | 0 | % | 30 | % |
| Oil and  condensate (2)                       |       | 21,767                                                                     |       | 17,336                          |       | 8,535 |   | 26 | % | 103 | % |
| Gain (loss) on  hedging and derivatives       |       | 9,730                                                                      |       | (2,267                          | )          | (2,460 | ) | * |   | 8 | % |
| Total (3)                                     |       | $                                                                          | 129,744    |                            | $          | 121,183 |   | $ | 64,505 |   | 7 | % | 88 | % |

 

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(1) Prices are calculated based on wholenumbers, not rounded numbers.  

(2) Excludes the effect of hedging andderivative transactions.

(3) Includes the effect of hedging and derivativetransactions.

*Notmeaningful, as different accounting treatment between reporting periods affectscomparability.

**Natural gas revenue** -Natural gas revenue, excluding hedging activity, decreased 8% for the yearended December 31, 2006 over the same period in 2005 and increased 86% for theyear ended December 31, 2005 over the same period in 2004. This growth from2004 to 2005 resulted from significantly higher production and higher realizedprices, whereas the decline in natural gas revenue from 2005 to 2006 was due tolower average realized

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prices that werepartially offset by higher production levels. Average natural gas productionincreased from 25.0 MMcf/d in 2004 to 34.5 MMcf/d in 2005 and to 37.9 MMcf/d in2006. Production increases in 2005 and 2006 as compared to 2004 have beenattributable in part to significant drilling at our Queen City and southeastNew Mexico properties. In addition, a significant amount of growth has comefrom acquisitions, including the existing production in the Queen City trend inlate 2004, the Chapman Ranch Field in late 2005 and additional workinginterests in the Chapman Ranch Field in December of 2006, for which the impactshould be more noticeable in 2007. Partially offsetting the increases in production were natural declinesat our O’Connor Ranch East and Brandon projects in 2005 as compared to 2004,and natural declines in production in our older properties including GatoCreek, Encinitas and Miller in 2006 as compared to 2005. Excluding the effectof hedges, the average natural gas sales price for production in 2006 was $6.68per Mcf compared to $7.97 per Mcf for 2005. This decrease in average pricereceived resulted in decreased revenue of approximately $17.8 million (based on2006 year production). The overall increase in production in 2006 compared to2005 resulted in an increase in revenue of approximately $10.0 million (basedon 2005 comparable period pre-hedge prices). The overall increase in production in 2005 compared to 2004 resulted inan increase in revenue of approximately $20.4 million (based on 2004 comparableperiod pre-hedge prices).  Excluding theeffect of hedges, the average natural gas sales price for production in 2005was $7.97 per Mcf compared 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).

**NGL revenue** - Revenue fromthe sale of NGLs remained flat for the year ended December 31, 2006 over thesame period in 2005 and increased 30% for the year ended December 31, 2005 overthe same period in 2004.  Dailyproduction volumes for NGLs increased from 755 Bbls/d for the year endedDecember 31, 2004 to 843 Bbls/d for 2005 and decreased to 608 Bbls/d in2006.  The increase from 2004 to 2005 isprimarily due to increased production from new wells drilled at Gato Creek,Encinitas, Santellana and southeast New Mexico and new processing and treatingagreements entered into during 2004 which increased production in 2005.  The decrease from 2005 to 2006 is mainlyattributed to production declines at our Encinitas, Gato Creek and Louisianaproperties.  The average realized pricefor NGLs for the year ended December 31, 2006 was $25.52 per barrel as comparedto $18.45 per barrel in 2005 and $15.83 per barrel for the same period in 2004.  The increase in NGL production in 2005increased revenue by approximately $0.5 million (based on 2004 comparableperiod average prices).  Higher averagerealized prices for the year ended December 31, 2005 resulted in an increase inrevenue of approximately $0.8 million (based on 2005 production).

**Crude oil and condensate revenue**- Revenue from the sale of oil and condensate, excluding derivative activity,increased 26% for the year ended December 31, 2006 over the same period in 2005and 103% for the year ended December 31, 2005 as compared to the same period in2004 due to increased realized prices and production. The average realizedprice for oil and condensate before the derivative gains for the year endedDecember 31, 2006 was $63.10 per barrel compared to $53.57 per barrel in thesame period of 2005.  These higheraverage prices for 2006 resulted in an increase in revenue of approximately$3.3 million (based on 2006 production). The average realized price for oil andcondensate before the derivative gains or losses for the year ended December31, 2005 was $53.57 per barrel compared to $39.77 per barrel in the same periodof 2004. These higher average prices for 2005 resulted in an increase inrevenue of approximately $4.5 million (based on 2005 production). Productionvolumes for oil and condensate increased to 945 Bbls/d for the year endedDecember 31, 2006 from 887 Bbls/d for the same period in 2005 and 586 Bbls/dfor the same period in 2004.  Theincrease in 2006 as compared to 2005 was from production on new wells drilledin our Queen City and southeast New Mexico projects, as well as from theChapman Ranch Field properties acquired in late 2005, partially offset bydeclines in production from our Miller, Encinitas, and Gato Creekproperties.  The increase in 2006 oil andcondensate production as compared to 2005 resulted in an increase in revenue ofapproximately $1.1 million (based on 2005 comparable period averageprices).  The increase in 2005 ascompared to 2004 was due primarily to successful drilling in southeast NewMexico and at our Queen City and Encinitas projects, as well as the acquisitionof existing production in the Queen City trend on December 29, 2004, partiallyoffset by declines at the Duson Horst and Brandon projects. The increase in2005 oil and condensate production as compared to 2004 resulted in an increasein revenue of approximately $4.3 million (based on 2004 comparable periodaverage prices).

**Hedging and derivatives** -Our hedging and derivative contracts resulted in a net gain in 2006 as comparedto net losses in 2004 and 2005. During the first quarter of 2006, wediscontinued cash flow hedge accounting treatment applied to our natural gascollars, due to projected changes in 2006 physical production volumes hedgedand to give us more flexibility in how we market our physical production.  This change in accounting treatment affectsthe

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comparability of theperiods (see Note 9 to our consolidated financial statements) because thechange in fair market value of the natural gas hedge contracts in 2005 wasdeferred through OCI on the balance sheet rather than presented in totalrevenue on the income statement, as presented in 2006. The volume and pricecontract terms vary from period to period and therefore interact differentlywith the changing pricing environment. While we are unable to predict themarket prices, we enter into contracts that we expect will protect us in theevent of significant downturns in the market, which has proven to be a benefitto us in 2006, with declining natural gas prices resulting in cash settlementinflows from our hedge counterparties to offset the lower prices received for ourphysical production. The following table summarizes the various components ofthe total gain or loss on hedging and derivatives for each of the periodsindicated and the impact each component had on our realized prices:
| ** **                                                                                                  | ** ** | **Year Ended December 31,**       | ** ** |
|-------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------------|------------|
| ** **                                                                                                  | ** ** | **2006**                                         | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                                                  | ** ** | **(in thousands, except prices)** | ** ** |
| ** **                                                                                                  | ** ** | **$**                                            | ** ** | **$ per unit** | ** ** | **$** | ** ** | **$ per unit** | ** ** | **$** | ** ** | **$ per unit** | ** ** |
| Natural gas  contract settlements (Mcf)                                                                     |       | $                                                | 4,699      |   | $ | 0.34 |   | $ | (1,230 | ) | $ | (0.10 | ) | $ | (328 | ) | $ | (0.04 | ) |
| Crude oil  contract settlements (Bbl)                                                                       |       | —                                           |       | — |   | (1,757 | ) | (5.43 | ) | (881 | ) | (4.10 | ) |
| Hedge premium  reclassification (Mcf)                                                                       |       | —                                           |       | — |   | — |   | — |   | (686 | ) | (0.08 | ) |
| Mark-to-market  unrealized change in fair value of gas derivative contracts (Mcf)                           |       | 4,686                                            |       | 0.34 |   | — |   | — |   | — |   | — |   |
| Mark-to-market  reversal of prior period unrealized change in fair value of oil derivative  contracts (Bbl) |       | (155                                             | )          | (0.45 | ) | 565 |   | 1.74 |   | — |   | — |   |
| Mark-to-market  unrealized change in fair value of oil derivative contracts (Bbl)                           |       | 500                                              |       | 1.45 |   | 155 |   | 0.48 |   | (565 | ) | (2.63 | ) |
| Gain (loss) on hedging and derivatives (Mcfe)                                                               |       | $                                                | 9,730      |   | $ | 0.56 |   | $ | (2,267 | ) | $ | (0.14 | ) | $ | (2,460 | ) | $ | (0.20 | ) |

 

**Should crude oil or natural gasprices increase or decrease from the current levels, it could materially impactour 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 these commodities are vulnerable to the volatilityof market price movements.  Therefore, wetypically enter into contracts covering only a portion of anticipatedproduction to ensure certain revenues that allow us to plan our business activities.**

**Costs andOperating Expenses**

The tablebelow presents a detail of expenses for the periods indicated:
| ** **                                            | ** ** | **December 31,**                                 | ** ** | **% Increase (Decrease)** | ** ** |
|-------------------------------------------------------|------------|-------------------------------------------------------|------------|-------------------------------------|------------|
| ** **                                            | ** ** | **2006**                                              | ** ** | **2005**                            | ** ** | **2004** | ** ** | **06 vs.  05** | ** ** | **05 vs.  04** | ** ** |
| ** **                                            | ** ** | **(in thousands, except percentages)** | ** ** |
| Oil and natural  gas operating expenses               |       | $                                                     | 9,122      |                                | $          | 8,478 |   | $ | 4,946 |   | 8 | % | 71 | % |
| Severance and ad  valorem taxes                       |       | 9,135                                                 |       | 8,590                               |       | 4,363 |   | 6 | % | 97 | % |
| Depreciation,  depletion, amortization and accretion: |       |                                                  |       |                                |       |   |   |   |   |   |   |
| Oil and natural gas property and equipment            |       | 60,472                                                |       | 39,810                              |       | 21,472 |   | 52 | % | 85 | % |
| Other assets                                          |       | 419                                                   |       | 267                                 |       | 357 |   | 57 | % | (25 | )% |
| ARO accretion                                         |       | 189                                                   |       | 141                                 |       | 99 |   | 34 | % | 43 | % |
| Impairment of  oil and natural gas properties         |       | 96,942                                                |       | —                              |       | — |   | * |   | * |   |
| General and  administrative expenses:                 |       |                                                  |       |                                |       |   |   |   |   |   |   |
| Bad debt expense                                      |       | —                                                |       | 65                                  |       | — |   | * |   | * |   |
| General and administrative expenses                   |       | 13,788                                                |       | 12,371                              |       | 9,447 |   | 11 | % | 31 | % |
| Total operating  expenses                             |       | 190,067                                               |       | 69,722                              |       | 40,684 |   | 173 | % | 71 | % |
| Other expense,  net                                   |       | 2,513                                                 |       | 25                                  |       | 437 |   | * |   | (94 | )% |
| Total expense                                         |       | $                                                     | 192,580    |                                | $          | 69,747 |   | $ | 41,121 |   | 176 | % | 70 | % |

 

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* Not meaningful

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**Oil and natural gas operating expenses**- Oil and natural gas operating expenses increased 71% between 2004 and 2005and 8% between 2005 and 2006, an 84% increase of 2006 over 2004. The increasefrom 2004 to 2006 has been driven by activity increases as well as costincreases. Activity levels were impacted by bringing online 62 apparentlysuccessful wells during 2005 and 43 apparently successful wells in 2006.  The 2005 and 2004 results were impacted bythe addition of the Miller and south Texas properties (acquisitions late in2003) that accounted for 26% of the total costs in 2004 and 23% in 2005. The2005 results had the added costs from the newly acquired Contango properties(late 2004), which account for 21% of total costs in 2005 and represent 50% ofthe increase from 2004 to 2005. The 2006 results were impacted by increasedcosts on our States, Gato Creek and southeast New Mexico properties.  We also experienced increases in 2006 due tothe Chapman Ranch properties acquired late in 2005, but costs for this areawere not as high as expected due to delays in our Chapman Ranch drillingprogram during 2006.  Operating expensesaveraged $0.53 per Mcfe, $0.52 per Mcfe and $0.41 per Mcfe for the years endedDecember 31, 2006, 2005 and 2004, respectively. The increasing cost structureresulted from added costs for compression, workovers and salt-water disposal aswell as inflation in our industry during 2006. We are witnessing increasingcosts due 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 great pressure on the economic stability and pricing structurewithin the industry. Typically, as prices for oil and natural gas increase, sodo many or all associated costs. When commodity prices decline, associatedcosts do not necessarily decline at the same rate.

**Severance and ad valorem taxes**- Severance tax expense for 2006 was 8% lower than 2005 whereas 2005 was 76%higher than 2004. Severance taxes are levied directly on our non-hedge revenuedollars, so the trend is consistent with our changes in revenue.  Total revenue subject to severance taxes in2006 was 2% lower than 2005 and 2005 was 85% higher than 2004.  The severance tax rate realized was 6.0% in2004 and then decreased to 5.7% in 2005 and further decreased to 5.4% in2006.  The rate realized changes as aresult of the changing mix of our production locations.  We had a significant portion of 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. In 2006, we received severance taxabatements on certain Chapman Ranch Field locations acquired late in 2005 as aresult of these properties qualifying for high-cost gas certification, whichlowered our severance tax rate further. Ad valorem costs increased 67% in 2006 as compared to 2005 and increased296% in 2005 compared to 2004.  Increasedcommodity prices in 2005 and 2006 resulted in a higher valuation of reserves bytaxing authorities and therefore higher ad valorem taxes on certainproperties.  Significant propertyacquisitions in late 2004 led to increased ad valorem taxes in 2005 andrepresented the majority of the increase from 2004 to 2005.  On an equivalent basis, severance and advalorem taxes averaged $0.53 per Mcfe, $0.52 per Mcfe and $0.36 per Mcfe forthe years ended December 31, 2006, 2005 and 2004, respectively.

**Depletion, depreciation and amortization (“DD&A”)and accretion expense** - DD&A and accretion expensefor the year ended December 31, 2006 increased 52% over the year ended December31, 2005 and 83% for the year ended December 31, 2005 over the year endedDecember 31, 2004.  Full-cost depletionon our oil and natural gas properties totaled $60.5 million in 2006, $39.8million in 2005 and $21.5 million in 2004. These increases were driven byproduction volume increases in 2004 and depletion rate increases in 2005 and2006.  For the year ended December 31,2006, depletion expense on a unit of production basis was $3.51 per Mcfe or 44%higher than the 2005 depletion rate of $2.43. The higher depletion rate increased depletion expense by approximately$18.6 million.  Higher production in 2006compared to 2005 increased depletion expense by approximately $2.1million.  For the year ended December 31,2005, higher oil and natural gas production compared to the prior year periodresulted in

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an increase indepletion expense of $7.6 million. Depletion expense on a unit of production basis for the year endedDecember 31, 2005 was $2.43 per Mcfe, 37% higher than the 2004 rate of $1.78per Mcfe. The higher depletion rate per Mcfe resulted in an increase indepletion 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 inreserves.

Depreciationof other assets increased 57% from 2005 to 2006 and decreased 25% from 2004 to2005.  Our depreciation expense relatedto other assets increased from 2005 to 2006 because we fully depreciatedcomputer software programs during the year and then replaced those sameprograms with new, upgraded technology. From 2004 to 2005 a decrease in depreciation expense occurred due toaccelerating depreciation on leasehold improvements and computer equipment in2003 and 2004.

Accretion expenseon our ARO liability increased 34% in 2006 and 43% in 2005 for the addition ofnew obligations associated with wells added each year, as well as the fact thataccretion is calculated using the interest method of allocation, whichcalculates interest on the cumulative balance such that the interest increaseswith each subsequent period.

**Impairment of oil and natural gas properties**– During the third quarter of 2006 we recorded a non-cash full-cost ceilingtest impairment of oil and natural gas properties in the amount of $96.9million ($63.0 million, net of tax), as discussed in Note 2 to the consolidatedfinancial statements.  No such impairmentwas necessary in 2005 or 2004.  Thewrite-down was primarily the result of the decline in natural gas prices atSeptember 30, 2006.  The natural gasprice used to calculate the full-cost ceiling at September 30, 2006 wassignificantly lower than the price at year-end 2005 and 2004 when no impairmentwas necessary.

**General and administrative (“G&A”) expenses**- Total G&A expenses for the year ended December 31, 2006 were $13.8million, an increase of 11% compared to the 2005 total of $12.4 million and 46%compared to the 2004 total of $9.4 million. The components of total G&A for 2004 and 2005 include compensationcosts in accordance with FIN 44 related to repriced options, amortization ofrestricted stock grants, bad debt expense and other corporate G&Acosts.   In 2006, in conjunction with theadoption of SFAS No. 123(R), we discontinued the application of FIN 44accounting treatment for repriced options and began recording compensationexpense for stock options that had not vested as of the date of adoption ofSFAS No. 123(R).

In2004 and 2005, FIN 44 accounting treatment was applied to our repriced options,which calls for a non-cashcharge to compensation expense if the price of our common stock on the lasttrading day of a reporting period is greater than the exercise price of certainrepriced options.  FIN 44 could alsoresult in a credit to compensation expense to the extent that the trading pricedeclines from the trading price as of the end of the prior period, but notbelow the exercise price of the options. In 2004 and 2005, we adjustedcompensation expense upward or downward monthly based on the trading price atthe end of each such period. We were required to report under this rule as aresult of non-qualified stock options granted to employees and directors inprior years and repriced in May of 1999, as well as certain newly issuedoptions in conjunction with the repricing. A FIN 44 charge on our repricedstock options was required in 2004 and 2005 as a result of our stock priceexceeding the exercise price of those repriced options. The average price atDecember 31, 2005 and 2004 that was used to calculate this expense was $24.65per share and $14.66 per share, respectively. In conjunction with theadoption of SFAS No. 123(R), we discontinued the application of FIN 44 andthere will not be any additional adjustments for charges or credits tocompensation expense related to repriced options.

Upon adoption of SFAS No. 123(R), as discussed inNotes 2 and 17 to the consolidated financial statements, during 2006, werecorded $68,937 in compensation expense for stock options that had not vestedas of adoption of SFAS No. 123(R). Those options have since vested and we havenot issued new options since 2004.

Compensationexpense related to the amortization of restricted stock has increased from $0.5million in 2004 to $1.0 million in 2005 and to $1.9 million in 2006.  This gradual increase in compensation forrestricted stock awards is related to additional restricted stock awardsgranted in conjunction with our increase in employees from 2004 to 2006 as wellas the vesting of additional tranches of grants already awarded to existingemployees.

OtherG&A expenses, which does not include the compensation costs discussedabove, increased 20% over 2005, which was 25% higher than 2004. The increase inother G&A from 2004 to 2006 was in part attributable to the growth in ourcompany from 51 full-time employees at December 31, 2004 to 68 full-timeemployees and one part-time employee at December 31, 2006. In 2005, we addednew corporate office space to support our growth,

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which increasedour rent expense. We also were impacted by higher audit and legal fees andamounts spent on investor relations projects during 2005.  In 2005, we realized additional costs relatedto the 2004 Sarbanes-Oxley 404 Internal Control Report of approximately $92,700that were unexpected. These increases were partially offset by decreases ingeneral office related spending in 2004. Included in 2005 were charitablecontributions of $100,000 to the Hurricane Katrina relief effort and bad debtexpense of $65,157 for joint interest owner accounts receivable that we believewere uncollectible. In 2006, we experienced higher legal fees which were inconjunction with increased legal activity in Texas and Louisiana.  Also in 2006, we paid a franchise taxsettlement to the State of Texas of approximately $0.2 million and a litigationsettlement in the Broussard case of approximately $0.2 million (see Note 13 tothe consolidated financial statements). For the years ended December 31, 2006, 2005 and 2004, overheadreimbursement fees reduced G&A costs by approximately $429,600, $287,900and $262,000, respectively. We capitalized $3.0 million, $2.6 million and $2.2million of general and administrative costs in 2006, 2005 and 2004,respectively.  Other G&A expenses ona unit of production basis for the years ended December 31, 2006, 2005 and 2004were $0.68 per Mcfe, $0.60 per Mcfe and $0.65 per Mcfe, respectively.

**Otherincome (expense)** – For the years ended December 31, 2004and 2006, we capitalized a portion of our interest expense.  But in the year ended December 31, 2005, wecapitalized 100% of our interest expense because our unproved property balance exceededour weighted average debt balance.  AtDecember 31, 2006, 2005 and 2004 our unproved property balance was $57.6million, $36.9 million and $15.5 million, respectively.  We incurred higher interest costs for theyear ended December 31, 2006 than for the years 2005 and 2004 due to highercommitment fees and outstanding debt balances, and also due to interest paid onour franchise tax settlement in 2006 of approximately $40,150.  Interest costs on the franchise taxsettlement were not subject to capitalization. The table below details our interest expense, capitalized interest andweighted average debt for each of the periods indicated:
|                             | ** ** | **For the Year Ended December 31,** | ** ** |
|-----------------------------|------------|--------------------------------------------------------------|------------|
| ** **                  | ** ** | **2006**                                                     | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                  | ** ** | **(in thousands)**                                      | ** ** |
| Gross interest              |       | $                                                            | 7,761      |   | $ | 1,943 |   | $ | 1,033 |   |
| Less:  capitalized interest |       | (5,261                                                       | )          | (1,943 | ) | (702 | ) |
| Interest  expense, net      |       | $                                                            | 2,500      |   | $ | — |   | $ | 331 |   |
|                        |       |                                                         |       |   |   |   |   |
| Weighted Average Debt       |       | $                                                            | 102,077    |   | $ | 24,189 |   | $ | 20,027 |   |

 

Includedin other income (expense) for the years ended December 31, 2006, 2005 and 2004was $165,211, $152,723 and $142,135, respectively, representing amortization ofdeferred loan costs associated with our then-existing credit facility.

Alsoincluded in other income (expense) was interest income, which totaled $152,184,$127,993, and $36,075 for the years ended December 31, 2006, 2005 and 2004,respectively. The interest is earned on daily cash invested in overnight moneymarket funds. We have had increased cash on hand in recent years providing forthe increased interest income.

**Income tax expense/benefit** - We are subject to state and federalincome taxes and although we were recently generating taxable income forfinancial reporting purposes, we are not in a federal income tax payingposition as a result of deducting intangible drilling costs (“IDC”) that reduceour taxable income for income tax purposes and NOL carryforwards that offsetany remaining taxable income. A deferred income tax benefit of $21.6 millionwas recorded for the year ended December 31, 2006, as we reported a net lossfor the year, primarily due to the full-cost ceiling test impairment recordedin the third quarter of 2006.  Deferredincome tax provisions of $18.1 million and$8.3 million were recorded for the years ended December 31, 2005 and 2004,respectively. The majority of the increase year over year has been the growthin income before income taxes. Due to changes in amounts of permanent taxdifferences, including meals and entertainment and compensation expense, oureffective tax rate also changes from time to time. The effective rate was 34.3%for the year ended December 31, 2006, as compared to 35.2% in 2005 and 35.3% in2004. As of December 31, 2006, approximately $73.6 million of net operatingloss carryforwards have been accumulated or acquired that will begin to expirein 2012.  We were required to makealternative minimum tax payments for 2006 of $94,100 and of $327,400 in2005.  No such alternative minimum taxpayments were made in 2004.

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**Earnings/loss per share** -For the year ended December 31, 2006, we had a net loss of $41.3 million, or$2.38 per basic and diluted loss per share, as compared to net income of $33.4million, or $1.95 basic earnings per share and $1.87 diluted earnings per share,in the same period of 2005 and net income of $15.1 million, or $1.16 basic and$1.11 diluted earnings per share, in 2004. Basic weighted average shares outstanding increased from approximately13.0 million at December 31, 2004 to 17.1 million at December 31, 2005 and to17.4 million at December 31, 2006.  Therewere also minimal increases due to options exercised and vesting of restrictedstock during 2004, 2005 and 2006.

## **LIQUIDITYAND CAPITAL RESOURCES**

Ourprimary ongoing source of capital is the cash flow generated from our operatingactivities supplemented by borrowings under our credit facility.  Net cash generated from operating activitiesis a function of production volumes and commodity prices, both of which areinherently volatile and unpredictable, as well as operating efficiency andcapital spending. Our business, as with other extractive businesses, is adepleting one in which each gas equivalent unit produced must be replaced orour asset base and capacity to generate revenues in the future will shrink. Ouroverall expected future production decline is estimated to be approximately 22%per year. Less predictable than production declines from our proved reserves isthe impact of constantly changing oil and natural gas prices on cash flows and,therefore capital budgets.  We attempt tomitigate the price risk with our hedging program. Reserves and productionvolumes are influenced, in part, by the amount of future capital expenditures.In turn, capital expenditures are influenced by many factors including drillingresults, oil and gas prices, industry conditions, prices, availability of goodsand services and the extent to which oil and gas properties are acquired.

Ourprimary cash requirements are for exploration, development and acquisition ofoil and gas properties, and the repayment of principal and interest onoutstanding debt. We attempt to fund our exploration and development activitiesprimarily through internally generated cash flows and budget capitalexpenditures based on projected cash flows. We routinely adjust capitalexpenditures in response to changes in oil and natural gas prices, drilling andacquisition costs, and cash flow. We have historically used our credit facilityto supplement any deficiencies between operating cash flow and capitalexpenditures. We typically have funded acquisitions from borrowings under ourcredit facility, cash flow from operations and sales of common stock andpreferred stock.

Significantchanges to working capital may affect our liquidity in the short term. Theincrease in our derivative instrument asset is indicative of potential futurecash settlement inflows on our hedge positions, which are scheduled to settlein future months. The fair value of our outstanding derivative contracts isreflected on the balance sheet as a current asset and a long-term liability forthe positions with each of our two counterparties. Our derivative financialinstrument asset represents future potential cash inflows as of the balancesheet date, such that if the contracts were to settle at the balance sheet datewe would have significant potential gains. The fair market value represents thepotential settlement for those contracts if the market prices remain unchanged,but should commodity prices increase or decrease, the fair value of thoseoutstanding contracts would change and the settlements at maturity would alsochange. When our derivatives result in cash inflows on settlements, we receivelower cash inflows on the sale of unhedged production at lower market prices,thus providing us with fewer funds with which to cover any derivative paymentsthat may come due in the future.

We have historically used our credit facility tosupplement any deficiencies between operating cash flow and capitalexpenditures.  Our outstanding debtbalance has increased from $20.0 million at December 31, 2004, to $85.0 millionat year-end 2005, to $129.0 million at December 31, 2006, and to $235.0 millionat March 9, 2007, primarily due to the funding of our acquisition program,principally the 2005 and 2006 acquisitions in the Chapman Ranch field, throughborrowings under our then-existing credit facility.

After considering the impact of these working capitalchanges and our forecasts of future results of operations, we believe that cashflows from operating activities, as supplemented by borrowings under our creditfacility, combined with our ability to control the timing of certain of ourfuture exploration and development requirements, will provide us with theflexibility and liquidity to meet our planned capital requirements for 2007.Our new revolving credit facility had $85.0 million available for borrowing atMarch 9, 2007.

During 2004 and early2005, we realized increased cash flows as a result of our public stockofferings and exercises of options and warrants to acquire shares of our commonstock. Most significant were the net proceeds of $47.8 million that wereceived, before direct costs of $0.6 million, from our December 2004 offeringof our common stock and the related exercise of the underwriter’sover-allotment option for 0.5 million additional shares of our 

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common stock, resulting in an additional$7.2 million of net proceeds to us in January 2005. At December 31, 2005 and2006, we had certain options outstanding and exercisable for shares of ourcommon stock. We typically do not rely on proceeds from the exercise ofwarrants and stock options to sustain our business, as the timing of theirexercise is unpredictable.

We had cash and cashequivalents at December 31, 2006 of $2.1 million consisting primarily ofshort-term money market investments, as compared to $0.7 million at December31, 2005.  Working capital was $10.2million as of December 31, 2006, as compared to $10.5 million at December 31,2005.
|                                              | ** ** | **For the Year Ended December 31,** | ** ** |
|----------------------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                                   | ** ** | **2006**                                                     | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                   | ** ** | **(in thousands)**                                      | ** ** |
| *Net  Cash Provided By Operating Activities* |       | $                                                            | 97,409     |   | $ | 93,111 |   | $ | 42,270 |   |
| *Net  Cash Used In Investing Activities*     |       | (140,412                                                     | )          | (167,280 | ) | (89,410 | ) |
| *Net Cash Provided by Financing  Activities* |       | 44,418                                                       |       | 72,568 |   | 48,080 |   |
|                                              |            |                                                              |            |  |  |  |  |  |  |  |

 

**Net Cash Provided By Operating Activities**- Cash flows provided by operating activities were $97.4 million, $93.1 millionand $42.3 million for the years ended December 31, 2006, 2005, and 2004,respectively.  The significant increasein cash flows provided by operating activities for the year ended December 31,2005 compared to 2004 was primarily due to higher oil and gas productionrevenue partially offset by higher operating expense, and the increase from2005 to 2006 occurred for the same reasons, only to a lesser extent.

Netcash generated from operating activities is a function of commodity prices,which are inherently volatile and unpredictable, production and capitalspending. In an effort to reduce the volatility realized on commodity prices,we enter into derivative instruments. Due to lower natural gas market pricing, we realized a benefit in cashsettlement gains of $4.7 million on our natural gas derivatives during 2006. Overall,oil and gas production revenue for 2006 increased 7% over 2005 and 101% over2004.

Althoughfluctuations in commodity prices have been the primary reason for ourshort-term changes in cash flow from operating activities, increased productionvolumes also impacted us in 2006. Our business, as with other extractivebusinesses, is a depleting one in which each gas equivalent produced must bereplaced or our asset base and capacity to generate revenues in the future willshrink. Our ability to prevent shrinkage will be affected in the future by thesuccesses and/or failures of our exploration, production and acquisitionactivities. Less predictable than production declines from our proved reservesis the impact of constantly changing oil and natural gas prices on cash flowsand, therefore, capital budgets.

Forthese reasons, we put in place an annual budget that is based upon ourforecasts for production, revenues and costs. Those forecasts are reviewed and updated regularly by management and ourcapital budget is adjusted as warranted. Longer term forecasts are used to assist our strategic planning andlong-term capital planning.

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

***NetCash Used In Investing Activities*** - We reinvest a substantialportion of our cash flows in our drilling, acquisition, land and geophysicalactivities.  As a result, we used $140.4million in investing activities during 2006. Capital expenditures of $82.6million were attributable to the drilling of 52 gross wells, 43 of which wereapparently successful. Acquisition costs totaled $39.4 million, mainly relatedto the acquisition of additional interests in the Chapman Ranch Field late in2006 and final adjustments to the Cinco purchase price. Other spending included$14.0 million attributable to land holdings, capitalized G&A and interestand $7.7 million for increased seismic data and other geological andgeophysical expenditures. Drilling advances to the operator of our Queen Cityproperties decreased in 2006 to approximately $2.9 million.  We also received $0.6 million during 2006from the sale of our Buckeye properties. The remaining capital expenditureswere associated with computer hardware and office furniture and equipment.

***During the year ended December 31, 2005,we used $167.3 million in investing activities. Capital expenditures of $79.1million were attributable to the drilling of 65 gross wells, 62 of which wereapparently successful. Acquisition costs related to the private companycorporate acquisition totaled $39.0 million, net of cash acquired,***

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***and other acquisition costs totaled $28.0 million, mainlyrelated to the Chapman Ranch Field asset acquisition. Other spending included$14.4 million attributable to land holdings, capitalized G&A and interestand $2.5 million for increased seismic data and other geological andgeophysical expenditures. Drilling advances to the operator of our Queen Cityproperties amounted to $4.3 million during 2005. The remaining capitalexpenditures were associated with computer hardware, office furniture andequipment for the expansion into additional office space.***

***During the year ended December 31, 2004,we used $89.4 million in investing activities. Capital expenditures for the year ended December 31, 2004 were partiallyoffset by $60,000 of proceeds from the sale of one well and a gas cooler duringthe year. Capital expenditures of $45.7 million were attributable to thedrilling of 49 gross wells, 40 of which were successful. Acquisition coststotaled $40.0 million for the year ended December 31, 2004, which includes$39.8 million related to the Contango Asset Acquisition. Other spending included$2.6 million in expenditures attributable to land holdings and $0.6 million forincreased seismic data and other geological and geophysical expenditures.  The remaining capital expenditures wereassociated with computer hardware, office furniture and equipment for theexpansion into additional office space.***

Dueto our active exploration, development and acquisition activities, we haveexperienced, and expect to continue to experience, substantial working capitalrequirements.  We currently anticipatecapital expenditures in 2007 to be approximately $140 million. Approximately$111.0 million is allocated to our expected drilling and production activities;$21.0 million is allocated to land, legal and seismic activities; and $8.0million relates to capitalized interest, G&A and other. We intend to fundthese capital expenditures, and other commitments and working capitalrequirements with expected cash flow from operations and, to the extentnecessary, other sources. Should there be a change in our pricing or productionassumptions, we believe that we have sufficient financial flexibility fromother financing sources to meet our financial obligations as they come due, andwe would recommend to our Board an adjustment to our capital expendituresprogram accordingly so as to avoid unnecessary incremental borrowings that maybe needed for acquisitions. We do not explicitly budget for acquisitions;however, we do expect to spend considerable effort evaluating acquisitionopportunities. We expect to fund acquisitions through traditional reserve-basedbank debt and/or the issuance of equity and, if required, through additionaldebt and equity financings.

**Net Cash Provided By Financing Activities**- Cash flows provided by financing activities totaled $44.4 million for theyear ended December 31, 2006. We had $62.0 million in borrowings and $18.0million in repayments under our credit facility. We incurred loan costs ofapproximately $0.2 million in amending our credit facility. In addition, wereceived $0.6 million in proceeds from the issuance of common stock related tooptions exercised in 2006.

Forthe year ended December 31, 2005, cash flows provided by financing activitiestotaled $72.6 million. We had $81.0 million in borrowings and $16.0 million inrepayments under our credit facility. We incurred loan costs of approximately$47,000 in amending our credit facility. In addition, we received $7.6 millionin proceeds from the issuance of common stock related to options exercised in2005. The majority of those proceeds are related to the January 2005underwriter exercise of the over-allotment option to the December 2004 commonstock offering. The funds generated from that exercise were used to reduce debtearly in 2005.

Forthe year ended December 31, 2004, cash flows provided by financing activitiestotaled $48.1 million including $27.0 million in borrowings and $28.0 millionin repayments under our credit facility. In addition, we completed a publicoffering of common stock in December 2004 that provided $47.2 million of netproceeds, after direct costs.  We alsoreceived approximately $2.3 million in proceeds from exercised stock optionsand warrants, and incurred approximately $0.4 million in loan costs in 2004.

Thecombination of unused debt capacity and possible sales of equity or debtsecurities should allow us the financial flexibility to continue to participatein acquisitions and complete our capital programs as we move into 2007.

***CreditFacility***

OnDecember 21, 2006, we amended our Third Amended and Restated Credit Agreement(the “Prior Credit Facility”), which we had originally entered into in March2004 (effective December 31, 2003) and previously amended on December 4,2006.  The Prior Credit Facilitypermitted borrowings up to the lesser of (i) the borrowing base and (ii) $150.0million. Effective December 2006, the borrowing base under the Prior CreditFacility was

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increased from$125.0 million to $140.0 million as a result of acquisitions and our drillingactivities since the last redetermination. Based on the increase, our availableborrowing capacity at December 31, 2006 was $11.0 million.

ThePrior Credit Facility’s scheduled maturity date was March 31, 2008, and it wassecured by substantially all of our assets. Borrowings under the Prior CreditFacility bore interest at rates that were variable based on the percentageusage of the facility. Borrowings could be at Prime plus a margin of up to0.25% or at LIBOR plus a margin of 1.75% to 2.125%.  As of December 31, 2006, our interest rateson our outstanding Prime and LIBOR borrowings were 8.500% and 7.485%,respectively. As of December 31, 2006, $129.0 million in borrowings wereoutstanding under the Prior Credit Facility.

ThePrior Credit Facility provided for certain restrictions and covenants, includingbut not limited to, limitations on additional borrowings, sales of oil andnatural gas properties or other collateral, and engaging in merger orconsolidation transactions. The Prior Credit Facility also prohibited dividendson our common stock and certain distributions of cash or properties and certainliens.  The Prior Credit Facility alsocontained the following financial covenants, among others:

·                  The EBITDAX toInterest Expense ratio required that the ratio of (a) our consolidated EBITDAX(defined as EBITDA plus similar non-cash items and exploration and abandonmentexpenses for such period) for the four fiscal quarters then ended to (b) ourconsolidated interest expense for the four fiscal quarters then ended, to notbe less than 3.5 to 1.0.

·                  The WorkingCapital ratio required that the amount of our consolidated current assets lessour consolidated current liabilities, as defined in the Credit FacilityAgreement, be at least $1.0 million. For the purposes of calculating theWorking Capital ratio, the total of current assets was adjusted for unusedcapacity under the Credit Facility Agreement, and derivative financialinstruments and the total of current liabilities was adjusted for the currentportion of indebtedness under the Credit Facility Agreement, derivativefinancial instruments and asset retirement obligations.

·                  TheMaximum Leverage ratio required that the ratio, as of the last day of anyfiscal quarter, of (a) Total Indebtedness (as defined in the Credit FacilityAgreement) as of such fiscal quarter to (b) an amount equal to consolidatedEBITDAX for the two quarters then ended times two, not be greater than 3.0 to1.0.

ConsolidatedEBITDAX is a component of negotiated covenants with our lenders and is definedabove as part of our disclosure of our covenant obligations.

As discussed inNote 12 to our consolidated financial statements, subsequent to year-end onJanuary 30, 2007, the Company entered into a Fourth Amended and Restated CreditAgreement (the “Agreement”) for a new Revolving Credit Facility with Union Bankof California (“UBOC”), as administrative agent and issuing lender, and theother lenders party thereto. Pursuant  tothe Agreement, UBOC will act as the administrative agent for a senior, firstlien secured borrowing base revolving credit facility (the “Credit Facility”)in favor of us and certain of our wholly owned subsidiaries (which subsidiariesinclude Edge Petroleum Operating Company, Inc., Edge Petroleum ExplorationCompany, Miller Oil Corporation and Miller Exploration Company) in an amountequal to $750 million, of which only $320 million is available under theborrowing base established at the closing. The Credit Facility has a letter ofcredit sub-limit of $20 million. In connection with the Credit Facility, wepaid the lenders fees in an amount equal to 1.00% of the initial borrowing baseestablished under the Credit Facility, or $3.2 million, on January 31,2007.  We paid approximately $0.4 millionto the lenders for certain other administrative fees, fronting fees and workfees in connection with the Credit Facility. Upon initiation of the CreditFacility, we terminated our existing Third Amended and Restated CreditAgreement described above and repaid the $129.0 million in borrowings under thePrior Credit Facility with proceeds from the public offerings described belowand in Note 12 to the consolidated financial statements.

The CreditFacility matures on January 31, 2011 and bears interest at LIBOR plus anapplicable margin ranging from 1.25% to 2.5%, with an unused commitment feeranging from 0.50% to 0.25%.

The CreditFacility provides for certain restrictions, including, but not limited to,limitations on additional borrowings, sales of oil and natural gas propertiesor other collateral, and engaging in merger or consolidation transactions. TheCredit Facility restricts dividends and certain distributions of cash orproperties and certain liens and also contains financial covenants including,without limitation, the following:

·      An EBITDAX to interest expense ratio requiresthat as of the last day of each fiscal quarter the ratio of (a) ourconsolidated EBITDAX (defined as EBITDA plus similar non-cash items andexploration and abandonment expenses for such period) to (b) our consolidatedinterest expense, not be less than 2.5 to 1.0, calculated on a cumulativequarterly basis for the first 12 months after the closing of the CreditFacility and then on a rolling four quarter basis.

·      A current ratio requires that as of thelast day of each fiscal quarter the ratio of ourconsolidated current assets toour consolidated current liabilities, as defined in the Credit Facility, be atleast 1.0 to 1.0.

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

The CreditFacility includes other covenants and events of default that we believe arecustomary for similar facilities. As of March 9, 2007, $235.0 million inborrowings were outstanding under the Credit Facility, as a result of the Smithacquisition and the refinancing of the Prior Credit Facility.

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***Shelf Registration Statement***

During the secondquarter 2005, we filed a registration statement with the SEC which registeredofferings of up to $390.0 million of any combination of debt securities,preferred stock, common stock or warrants for debt securities or equitysecurities of the Company. Net proceeds, terms and pricing of the offering ofsecurities issued under the shelf registration statement will be determined atthe time of the offerings. The shelf registration statement does not provideassurance that we will or could sell any such securities. Our ability toutilize our shelf registration statement for the purpose of issuing, from timeto time, any combination of debt securities, preferred stock, common stock orwarrants for debt securities or equity securities will depend upon, among otherthings, market conditions and the existence of investors who wish to purchaseour securities at prices acceptable to us. In connection with the filing of the2005 registration statement, we deregistered the remaining shares thenavailable for sale under our earlier $150.0 million shelf registration statementfiled in 2004.

OnDecember 21, 2004, we completed an offering of 3.5 million shares of our commonstock, which generated net proceeds to us, before direct costs of the offering,of $47.8 million. These funds were used to finance the south Texas asset acquisitionthat closed on December 29, 2004 with a final adjusted purchase price of $40.1million, before other acquisition costs, and fund the costs of the offering andother general corporate purposes. On January 5, 2005, the underwritersexercised their over-allotment option for an additional 525,000 shares ofcommon stock, which generated net proceeds to us of $7.2 million. These fundswere used to reduce our outstanding debt. Each of these sales was made underour shelf registration statement. At December 31, 2006, we had $390.0 millionremaining for issuance under our 2005 shelf registration statement.

Asdiscussed in Note 12 to our consolidated financial statements, we completed apublic offering of 10.925 million shares of common stock and 2.875 millionshares of Series A cumulative convertible perpetual preferred stock subsequentto year-end.  These offerings generatedcombined estimated net proceeds to us, before direct costs of the offerings, of$276.7 million ($138.1 million in the common offering and $138.6 million in thepreferred offering).  These proceeds wereused to partially finance the Smith acquisition, which closed on January 31,2007, and to refinance our Prior Credit Facility.  At March 9, 2007, we had approximately $101.5million remaining available for issuance under our 2005 shelf registrationstatement.

***Convertible Preferred Stock***

In January 2007,we completed the public offering of 2,875,000 shares of our 5.75% Series Acumulative convertible perpetual preferred stock (“Convertible PreferredStock”) for net proceeds of approximately $138 million.  We used the proceeds from this offering,along with the proceeds from a concurrent common stock offering and along withborrowings under our current credit facility, to finance the Smith acquisitionand to refinance our prior credit facility.

*Dividends*.  The Convertible Preferred Stock accumulatesdividends at a rate of $2.875 for each share of Convertible Preferred Stock peryear. Dividends are cumulative from the date of first issuance and, to theextent payment of dividends is not prohibited by our debt agreements, assetsare legally available to pay dividends and our board of directors or anauthorized committee of our board declares a dividend payable, we will paydividends in cash, every quarter. 

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

*Liquidationpreference*.  In theevent of our voluntary or involuntary liquidation, winding-up or dissolution,each holder of Convertible Preferred Stock will be entitled to receive and tobe paid out of our assets available for distribution to our stockholders,before any payment or distribution is made to holders of junior stock(including common stock), but after any distribution on any of our indebtednessor senior stock, a liquidation preference in the amount of $50 per share of theConvertible Preferred Stock, plus accumulated and unpaid dividends on theshares to the date fixed for liquidation, winding-up or dissolution. 

*Ranking*.  Our Convertible Preferred Stock ranks: 

·      senior to all of the shares of our commonstock and to all of our other capital stock issued in the future unless theterms of such capital stock expressly provide that it ranks senior to, or on aparity with, shares of our Convertible Preferred Stock;

·      on a parity with all of our other capitalstock issued in the future the terms of which expressly provide that it willrank on a parity with the shares of our Convertible Preferred Stock; and 

·      junior to all of our existing and futuredebt obligations and to all shares of our capital stock issued in the futurethe terms of which expressly provide that such shares will rank senior to theshares of our Convertible Preferred Stock. 

*Mandatory conversion*. On or afterJanuary 20, 2010, we may, at our option, cause shares of our ConvertiblePreferred Stock to be automatically converted at the applicable conversionrate, but only if the closing sale price of our common stock for 20 tradingdays within a period of 30 consecutive trading days ending on the trading dayimmediately preceding the date we give the conversion notice equals or exceeds130% of the conversion price in effect on each such trading day. 

Optionalredemption. If fewer than 15% of the shares of Convertible Preferred Stockissued in the Convertible Preferred Stock offering (including any additionalshares issued pursuant to the underwriters' over-allotment option) areoutstanding, we may, at any time on or after January 20, 2010, at our option,redeem for cash all such Convertible Preferred Stock at a redemption priceequal to the liquidation preference of $50 plus any accrued and unpaiddividends, if any, on a share of Convertible Preferred Stock to, but excluding,the redemption date, for each share of Convertible Preferred Stock. 

*Conversion rights*. Each share ofConvertible Preferred Stock may be converted at any time, at the option of theholder, into approximately 3.0193 shares of our common stock (which is based onan initial conversion price of $16.56 per share of common stock, subject toadjustment) plus cash in lieu of fractional shares, subject to our right tosettle all or a portion of any such conversion in cash or shares of our commonstock. If we elect to settle all or any portion of our conversion obligation incash, the conversion value and the number of shares of our common stock we willdeliver upon conversion (if any) will be based upon a 20 trading day averagingperiod. 

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Uponany conversion, the holder will not receive any cash payment representingaccumulated and unpaid dividends on the Convertible Preferred Stock, whether ornot in arrears, except in limited circumstances. The conversion rate is equalto $50 divided by the conversion price at the time. The conversion price issubject to adjustment upon the occurrence of certain events. The conversionprice on the conversion date and the number of shares of our common stock, asapplicable, to be delivered upon conversion may be adjusted if certain eventsoccur. 

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

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

A"fundamental change" will be deemed to have occurred upon theoccurrence of any of the following: 

1.     a "person" or "group"subject to specified exceptions, disclosing that the person or group has becomethe direct or indirect ultimate "beneficial owner" of our commonequity representing more than 50% of the voting power of our common equityother than a filing with a disclosure relating to a transaction which complieswith the proviso in subsection 2 below;

2.     consummation of any share exchange,consolidation or merger of us pursuant to which our common stock will beconverted into cash, securities or other property or any sale, lease or othertransfer in one transaction or a series of transactions of all or substantiallyall of the consolidated assets of us and our subsidiaries, taken as a whole, toany person other than one of our subsidiaries; provided, however, that atransaction where the holders of more than 50% of all classes of our commonequity immediately prior to the transaction own, directly or indirectly, morethan 50% of all classes of common equity of the continuing or survivingcorporation or transferee immediately after the event shall not be afundamental change; 

3.     we are liquidated or dissolved or holdersof our capital stock approve any plan or proposal for our liquidation ordissolution; or 

4.     our common stock is neither listed on anational securities exchange nor listed nor approved for quotation on anover-the-counter market in the United States. 

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

*Voting rights*. If we fail to paydividends for six quarterly dividend periods (whether or not consecutive) or ifwe fail to pay the purchase price on the purchase date for the Convertible PreferredStock following a

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fundamental change,holders of our Convertible Preferred Stock will have voting rights to elect twodirectors to our board. 

Inaddition, we may generally not, without the approval of the holders of at least66 2/3% of the shares of our Convertible Preferred Stock then outstanding: 

·      amendour restated certificate of incorporation, as amended, by merger or otherwise,if the amendment would alter or change the powers, preferences, privileges orrights of the holders of shares of our Convertible Preferred Stock so as toadversely affect them;

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

·      reclassifyany of our authorized stock into any senior stock of any class, or anyobligation or security convertible into or evidencing a right to purchase anysenior stock.

***Off Balance Sheet Arrangements***

The Companycurrently does not have any off balance sheet arrangements.

***Contractual Cash Obligations***

The followingtable summarizes our contractual cash obligations as of December 31, 2006 bypayment due date:

|                                            | ** ** | **Total**               | ** ** | **Less  than 1  Year** | ** ** | **1-3 Years** | ** ** | **4-5  Years** | ** ** | **After 5  Years** | ** ** |
|--------------------------------------------|------------|-------------------------|------------|-----------------------------|------------|--------------------|------------|----------------|------------|-------------------------|------------|
| ** **                                 | ** ** | **(in thousands)** | ** ** |
| Long-term debt  (1)                        |       | $                       | 129,000    |                        | $          | —             |       | $              | 129,000    |                    | $          | — |   | $ | — |   |
| Operating leases                           |       | 5,354                   |       | 817                         |       | 2,460              |       | 1,608          |       | 469                     |       |
| Total contractual cash  obligations (2)(3) |       | $                       | 134,354    |                        | $          | 817                |       | $              | 131,460    |                    | $          | 1,608 |   | $ | 469 |   |

 

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(1)          Excludes amounts forinterest expense payable upon outstanding debt. Long-term outstanding debtunder our credit facility is subject to floating interest rates (see Note 10 toour consolidated financial statements) and payable on the last day of eachcalendar month while any loan amounts remain outstanding.  We do not forecast debt repayments beyond thecurrent year.  Therefore, cash paymentsfor interest beyond one year cannot be estimated.  We expect to pay approximately $19.1 millionin interest during 2007.

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(2)          We did not have anycapital leases or purchase obligations as of December 31, 2006.

(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 do notaccount for salvage value on our balance sheet, but we do not expect to realizethe total value that we have accrued.

**RISKMANAGEMENT ACTIVITIES – DERIVATIVES AND HEDGING**

Dueto the volatility of oil and natural gas prices, we may enter into, from timeto time, price-risk management transactions (e.g., swaps, collars and floors)for a portion of our oil and natural gas production to achieve a morepredictable cash flow, as well as to reduce exposure to commodity pricefluctuations.  While the use of thesearrangements may limit our ability to benefit from increases in the price ofoil and natural gas, it also reduces our potential exposure to adverse pricemovements.  Our arrangements, to theextent we enter into any, apply to only a portion of our production, provideonly partial price protection against declines in oil and natural gas pricesand limit our potential gains from future increases in prices. None of theseinstruments are used for trading purposes. On a quarterly basis, our managementsets all of our price-risk management policies, including volumes, types ofinstruments and counterparties. These policies are implemented by managementthrough the execution of trades by the Chief Financial Officer afterconsultation and concurrence by the President and Chairman of the Board.  Our Board of Directors monitors the Company’sprice-risk management policies 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*(as amended).These derivative instruments are intended to hedge our price risk and may beconsidered hedges for economic purposes. There are two types of accountingtreatments for derivatives, (i) mark-to-market accounting and (ii) cash flowhedge accounting. For discussion of these accounting treatments, see Note 9 toour consolidated financial statements. During the first quarter of 2006, we discontinued cash flow hedgeaccounting treatment previously applied to our natural gas derivatives.Therefore, all derivatives are recorded on the balance sheet at fair value andthe changes in fair value are presented in total revenue on the incomestatement, rather than deferred through OCI on the balance sheet.. Thefollowing table provides additional information regarding our variousderivative transactions that were recorded at fair value on the balance sheetas of December 31, 2006.
| Fair value of contracts  outstanding at December 31, 2005                               |   | $      | (2,479 | )      |
|-----------------------------------------------------------------------------------------|--------|--------|--------|--------|
| Contracts  realized or otherwise settled during the period                              |   | 4,699  |   |
| Fair value of  new contracts when entered into during 2006:                             |   |   |   |
| Asset                                                                                   |   | 5,733  |   |
| Liability                                                                               |   | (546   | )      |
| Changes in fair  values attributable to changes in valuation techniques and assumptions |   | — |   |
| Other changes in  fair values                                                           |   | (2,220 | )      |
| Fair values of  contracts outstanding at December 31, 2006                              |   | $      | 5,187  |   |

 

The following table details the fair value of ourcommodity-based derivative contracts by year of maturity and valuationmethodology as of December 31, 2006.

|                                                      | ** ** | **Fair Value of Contracts at December 31, 2006** | ** ** |
|------------------------------------------------------|------------|-------------------------------------------------------------------------------------|------------|
| **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                                                |       | 5,945                                                                               |       | — |   | — |   | — |   | 5,945 |   |
| Liability                                            |       | —                                                                              |       | (758 | ) | — |   | — |   | (758 | ) |
| Prices based on  models and other valuation methods: |       | —                                                                              |       | — |   | — |   | — |   | — |   |
| Total                                                |       | $                                                                                   | 5,945      |   | $ | (758 | ) | $ | — |   | $ | — |   | $ | 5,187 |   |

 

**TAXMATTERS**

At December 31, 2006, wehave cumulative net operating loss carryforwards (“NOLs”) for federal incometax purposes of approximately $73.6 million, including $17.4 million and $5.4million of NOLs acquired in the Miller merger and Cinco acquisition,respectively, that expire beginning in 2012. These estimated NOLs assume thatcertain items, primarily intangible drilling costs, have been written off fortax purposes in the current year. However,

59

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we have not made a final determination ifan election will be made to capitalize all or part of these items for taxpurposes in the future.

**RECENTLY ISSUEDACCOUNTING PRONOUNCEMENTS**

In March 2006, the FASB issued SFAS No. 156, *Accounting for Servicing of Financial Assets*, which requiresall separately recognized servicing assets and servicing liabilities beinitially measured at fair value. SFAS No. 156 permits, but does not require,the subsequent measurement of servicing assets and servicing liabilities atfair value. Adoption is required as of the beginning of the first fiscal yearthat begins after September 15, 2006. Early adoption is permitted. Theadoption of SFAS No. 156 is not expected to have a material effect on ourconsolidated financial position, results of operations or cash flows.

In June 2006, the FASB issued FIN 48, *Accounting for Uncertainty in Income Taxes, an Interpretation of FASBStatement No. 109*, which clarifies the accounting foruncertainty in income taxes recognized in accordance withSFAS No. 109, *Accounting for IncomeTaxes*. FIN 48 prescribes a benefit recognition model with atwo-step approach, a more-likely-than-not recognition criterion and ameasurement attribute that measures the position as the largest amount of taxbenefit that is greater than 50% likely of being realized upon settlement. Ifit is not more likely than not that the benefit will be sustained on itstechnical merits, no benefit will be recorded. FIN 48 also requires thatthe amount of interest expense to be recognized related to uncertain taxpositions be computed by applying the applicable statutory rate of interest tothe difference between the tax position recognized in accordance withFIN 48 and the amount previously taken or expected to be taken in a taxreturn. The change in net assets as a result of applying this pronouncementwill be considered a change in accounting principle, with the cumulative effectof the change treated as an offsetting adjustment to the opening balance ofretained earnings or goodwill, if allowed under existing accounting standards,in the period of transition. FIN 48 is effective as of January 1,2007 and we are currently evaluating the effects, if any, that FIN 48 will haveon our financial statements.

In September 2006, the FASB issued SFAS No. 157, *Fair Value Measurements,* which provides guidance for usingfair value to measure assets and liabilities. The standard also gives expanded information about the extent to whichcompanies measure assets and liabilities at fair value, the information used tomeasure fair value, and the effect of fair value measurements on earnings. SFASNo. 157 does not expand the use of fair value in any new circumstances.  SFAS No. 157 establishes a fair valuehierarchy that prioritizes the information used to develop fair valueassumptions.  SFAS No. 157 is effectivefor financial statements issued for fiscal years beginning after November 15,2007.  Early adoption is encouraged.  We are currently assessing the impact, ifany, that SFAS No. 157 will have on our financial statements.

In February 2007, the FASB issued SFAS No. 159, *The Fair Value Option for Financial Assets and Financial Liabilities*,which permits entities to choose to measure many financial instruments andcertain other items at fair value.  Theobjective is to improve financial reporting by providing entities with theopportunity to mitigate volatility in reported earnings caused by measuringrelated assets and liabilities differently without having to apply complexhedge accounting provisions.  SFAS No.159 applies to all entities and is effective for fiscal years beginning afterNovember 15, 2007.  We are currentlydetermining the impact, if any, that SFAS No. 159 will have on our financialstatements.

***ITEM7A.  QUANTITATIVE AND QUALITATIVEDISCLOSURES ABOUT MARKET RISK***

We are exposed to market risk from changes in interestrates and commodity prices.  We use acredit facility, which has a floating interest rate, to finance a portion ofour operations. We are not subject to fair value risk resulting from changes inour floating interest rates.  The use offloating rate debt instruments provides a benefit due to downward interest ratemovements but does not limit us to exposure from future increases in interestrates.  Based on the year-end December31, 2006 outstanding borrowings and interest rates of 8.500% and 7.485% appliedto various borrowings, a 10% change in interest rate would result in anincrease or decrease in interest expense of approximately $1.0 million on anannual basis.

In the normal course of business, we enter intoderivative transactions, including commodity price collars, swaps and floors tomitigate our exposure to commodity price movements, but not for trading orspeculative purposes.  During 2006 andearly 2007, we put in place several natural gas and crude oil collars for aportion of our 2007 and 2008 production to achieve a more predictable cashflow. Please refer to Note 9 to our consolidated

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financial statements for a discussion of thesecollars. While the use of these arrangements may limit the benefit to us ofincreases in the price of oil and natural gas, it also limits the downside riskof adverse price movements.  Thefollowing is a list of contracts outstanding at December 31, 2006:
| **Transaction  Date**   | ** **   | **Transaction  Type** | ** **   | **Beginning** | ** **   | **Ending**   | ** **   | **Price   Per Unit** | ** **   | **Volumes Per  Day** | ** **   | **Fair Value  Outstanding as  of December 31,  2006** | ** **   |
|-------------------------|--------------|-----------------------|--------------|---------------|--------------|--------------|--------------|--------------------------------|--------------|---------------------------|--------------|---------------------------------------------------------------------------|--------------|
| *** ***            | *** *** | *** ***          | *** *** | *** ***  | *** *** | *** *** | *** *** | *** ***                   | *** *** | *** ***              | *** *** | **(in  thousands)**                                                       | *** *** |
| ***Natural  Gas (1):*** | * *     | * *              | * *     | * *      | * *     | * *     | * *     | * *                       | * *     | * *                  | * *     | * *                                                                  | * *     |
| *** ***            | * *     | * *              | * *     | * *      | * *     | * *     | * *     | * *                       | * *     | * *                  | * *     | * *                                                                  | * *     |
| 08/06                   |         | Collar                |         | 01/01/07      | (3)          | 12/31/07     |         | $7.50-$11.50                   |         | 5,000 MMbtu               |         | $                                                                         | 2,301        |   |
|                    |         |                  |         |          |         |         |         |                           |         |                      |         |                                                                      |         |
| 08/06                   |         | Collar                |         | 01/01/07      | (3)          | 12/31/07     |         | $7.50-$12.00                   |         | 5,000 MMbtu               |         | 2,385                                                                     |         |
|                    |         |                  |         |          |         |         |         |                           |         |                      |         |                                                                      |         |
| ***Crude  Oil (2):***   | *** *** | *** ***          | *** *** | *** ***  | *** *** | *** *** | *** *** | *** ***                   | *** *** | *** ***              | *** *** | *** ***                                                              | *** *** |
| *** ***            | *** *** | *** ***          | *** *** | *** ***  | *** *** | *** *** | *** *** | *** ***                   | *** *** | *** ***              | *** *** | *** ***                                                              | *** *** |
| 08/06                   |         | Collar                |         | 01/01/07      |         | 12/31/07     |         | $70.00-$87.50                  |         | 400 Bbl                   |         | 1,047                                                                     |         |
|                    |         |                  |         |          |         |         |         |                           |         |                      |         |                                                                      |         |
| 12/06                   |         | Swap                  |         | 01/01/07      |         | 12/31/07     |         | $66.00                         |         | 600 Bbl                   |         | 212                                                                       |         |
|                    |         |                  |         |          |         |         |         |                           |         |                      |         |                                                                      |         |
| 12/06                   |         | Swap                  |         | 01/01/08      |         | 12/31/08     |         | $66.00                         |         | 1,500 Bbl                 |         | (758                                                                      | )            |
|                    |         |                  |         |          |         |         |         |                           |         |                      |         | $                                                                         | 5,187        |   |

 

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(1)     Our current natural gas collars were enteredinto on a per MMbtu delivered price basis, using the Houston Ship ChannelIndex.  During 2005, cash flow hedgeaccounting was applied to these contracts, which was then discontinued in 2006.During 2006, mark-to-market accounting treatment was applied to these contractsand the change in fair value is reflected in total revenue during the year.

(2)     Cash flow hedge accounting is not applied toour crude oil contracts, which were entered into on a per barrel deliveredprice basis, using the West Texas Intermediate Light Sweet Crude Oil Index.Mark-to-market accounting treatment is applied to these contracts and thechange in fair value is reflected in total revenue during the year.

(3)     Subsequent to December 31, 2006, two naturalgas collars covering a portion of our 2007 estimated production were terminatedand replaced with new collars.  The termsof the new contracts are detailed in the table below.

At December 31, 2006, the fair value of theoutstanding contracts was a net asset of approximately $5.2 million (See *ITEM 7. “MANAGEMENT’S DISCUSSIONAND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS*–**RISKMANAGEMENT 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 hedge to increase or decrease by approximately $0.6 million.

Derivative contracts entered into after December 31,2006 were as follows: 
| ** **            | ** ** | **Effective Dates**           | ** ** |
|-----------------------|------------|------------------------------------|------------|
| **Transaction  Date** | ** ** | **Transaction Type (1)** | ** ** | **Beginning** | ** ** | **Ending** | ** ** | **Price Per Unit** | ** ** | **Volume Per  Day** | ** ** |
| 01/07                 |       | Natural Gas  Collar                |       | 01/01/08 |   | 12/31/08 |   | $7.50-$9.00 |   | 10,000 MMbtu |   |
| 01/07                 |       | Natural Gas Collar                 |       | 01/01/08 |   | 12/31/08 |   | $7.50-$9.02 |   | 10,000 MMBtu |   |
| 01/07                 |       | Natural Gas Collar                 | (2)        | 02/01/07 |   | 12/31/07 |   | $7.02-$9.00 |   | 15,000 MMBtu |   |
| 01/07                 |       | Natural Gas Collar                 | (2)        | 02/01/07 |   | 12/31/07 |   | $7.00-$9.00 |   | 15,000 MMBtu |   |
| 01/07                 |       | Natural Gas Collar                 |       | 02/01/07 |   | 12/31/07 |   | $7.00-$9.00 |   | 10,000 MMbtu |   |
| 01/07                 |       | Natural Gas Collar                 |       | 01/01/08 |   | 12/31/08 |   | $7.50-$9.00 |   | 20,000 MMBtu |   |

 

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(1)   Our January 2007 natural gas collars were entered into on a per MMbtudelivered price basis, using the NYMEX Natural Gas Index. Mark-to-marketaccounting treatment will be applied to these contracts and the change in fairvalue will be reflected in total revenue.

(2)   These natural gas collars replaced contracts that were cancelledsubsequent to December 31, 2006.

***ITEM8.  FINANCIAL STATEMENTS ANDSUPPLEMENTARY DATA***

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

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

None.

***ITEM9A. CONTROLS AND PROCEDURES***

**(a) Disclosure Controls and Procedures.** Wemaintain disclosure controls and procedures that are designed to providereasonable assurance that information required to be disclosed by us in thereports that we file or submit to the Securities and Exchange Commission (“SEC”)under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), isrecorded, processed, summarized and reported within the time periods specifiedby the SEC’s rules and forms, and that information is accumulated andcommunicated to our management, including our Chief Executive Officer and ChiefFinancial Officer, as appropriate to allow timely decisions regarding requireddisclosure.

In accordance withExchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under thesupervision and with the participation of management, including our ChiefExecutive Officer (“CEO”) and Chief Financial Officer (“CFO”), of theeffectiveness of our disclosure controls and procedures as of the end of theperiod covered by this report.  Asdescribed below under Management’s Annual Report on Internal Control overFinancial Reporting, our CEO and CFO have concluded that, as of the end of theperiod covered by this Annual Report on Form 10-K, the Company’s disclosurecontrols and procedures were effective to provide reasonable assurance thatinformation required to be disclosed in our reports filed or submitted underthe Exchange Act is recorded, processed, summarized and reported within thetime periods specified in the SEC’s rules and forms.

BDOSeidman, LLP’s audit report, dated March 9, 2007, expressed an unqualifiedopinion on our consolidated financial statements and its assessment ofManagement’s Annual Report on Internal Control over Financial Reporting isincluded herein under paragraph (d).

**(b) Management’s Annual Report on Internal Control overFinancial Reporting.**Management, including the CEO and CFO,has the responsibility for establishing and maintaining adequate internalcontrol over financial reporting, as defined in the Exchange Act, Rule13a-15(f).  Internal control overfinancial reporting is a process designed by, or under the supervision of, theCompany’s principal executive and principal financial officers, or personsperforming similar functions and influenced by the Company’s Board ofDirectors, management and other personnel, to provide reasonable assuranceregarding the reliability of financial reporting and the preparation of financialstatements for external purposes in accordance with accounting principlesgenerally accepted in the United States of America (“GAAP”).  Because of its inherent limitations, internalcontrol over financial reporting may not prevent or detect misstatements. Inaddition, projections of any evaluation of effectiveness to future periods aresubject to the risk that controls may become inadequate or insufficient becauseof changes in operating conditions, or that the degree of compliance with thepolicies or procedures may deteriorate.

A control deficiencyexists when the design or operation of a control does not allow management oremployees, in the ordinary course of performing their assigned functions, toprevent or detect misstatements on a timely basis.  A significant deficiency is a controldeficiency, or combination of control deficiencies, that adversely affects theCompany’s ability to initiate, authorize, record, process, or report externalfinancial data reliably in accordance with GAAP, such that there is a more thanremote likelihood that a misstatement of the Company’s annual or interimfinancial statements that is more than inconsequential will not be prevented ordetected.  A material weakness is acontrol deficiency, or combination of control deficiencies, that results inmore than a remote likelihood that a material misstatement of the annual orinterim financial statements will not be prevented or detected.

Management assessedinternal control over financial reporting of the Company and subsidiaries as ofDecember 31, 2006.  The Company’smanagement conducted its assessment in accordance with the *Internal Control*–*Integrated Framework* issued bythe Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).  Management has concluded that the internalcontrol over financial reporting was effective as of December 31, 2006.

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BDO Seidman, LLP, theindependent registered public accounting firm who also audited the Company’sconsolidated financial statements, has issued its own attestation report onmanagement’s assessment of the effectiveness of internal control over financialreporting as of December 31, 2006, which is filed herewith.

**(c) Changes in Internal Control OverFinancial Reporting.** There have not been any changes in the Company’s internal control overfinancial reporting during the fiscal quarter ended December 31, 2006 that havematerially affected, or are reasonably likely to materially affect, the Company’sinternal control over financial reporting.

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

Boardof Directors and StockholdersEdge Petroleum Corporation

Houston, Texas

We have audited management’s assessment, included inthe accompanying Management’s Report on Internal Control over FinancialReporting, that Edge Petroleum Corporation maintained effective internalcontrol over financial reporting as of December 31, 2006, based on criteria established in*Internal Control—Integrated Framework*issued by the Committee of Sponsoring Organizations of the Treadway Commission(COSO criteria). Edge Petroleum Corporation’s management is responsiblefor maintaining effective internal control over financial reporting and for itsassessment of the effectiveness of internal control over financial reporting.Our responsibility is to express an opinion on management’s assessment and anopinion on the effectiveness of the company’s internal control over financialreporting based on our audit.

We conducted our audit in accordance with thestandards of the Public Company Accounting Oversight Board (United States).Those standards require that we plan and perform the audit to obtain reasonableassurance about whether effective internal control over financial reporting wasmaintained in all material respects. Our audit included obtaining anunderstanding of internal control over financial reporting, evaluatingmanagement’s assessment, testing and evaluating the design and operatingeffectiveness of internal control, and performing such other procedures as weconsidered necessary in the circumstances. We believe that our audit provides areasonable basis for our opinion.

A company’s internal control over financial reportingis a process designed to provide reasonable assurance regarding the reliabilityof financial reporting and the preparation of financial statements for externalpurposes in accordance with accounting principles generally accepted in theUnited States of America. A company’s internal control over financial reportingincludes those policies and procedures that (1) pertain to the maintenance ofrecords that, in reasonable detail, accurately and fairly reflect thetransactions 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 accounting principlesgenerally accepted in the United States of America, and that receipts andexpenditures of the company are being made only in accordance withauthorizations of management and directors of the company; and (3) providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the company’s assets that could have amaterial effect on the financial statements.

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

In our opinion, management’s assessment that EdgePetroleum Corporation maintained effective internal control over financialreporting as of December 31, 2006, is fairly stated, in all material respects,based on the COSO criteria. Also in our opinion, Edge Petroleum Corporationmaintained, in all material respects, effective internal control over financialreporting as of December 31, 2006, based on the COSO criteria.

We have also audited, inaccordance with the standards of the Public Company Accounting Oversight Board(United States), the consolidated balance sheets of Edge Petroleum Corporationas of December 31, 2006 and 2005 and the related consolidated statements of operations,comprehensive income (loss), stockholders’ equity, and cash flows for each ofthe three years in the period ended December 31, 2006 and our reportdated March 9, 2007 expressed an unqualified opinion thereon.

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| /S/ BDO SEIDMAN, LLP |   |
|----------------------|--------|
|                 |
| BDO Seidman, LLP     |
| Houston, TX          |
| March 9, 2007        |

 

***ITEM9B. OTHER INFORMATION***

None.

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**PART III**

***ITEM10.  DIRECTORS, EXECUTIVE OFFICERS ANDCORPORATE GOVERNANCE***

Theinformation regarding directors and executive officers required under *ITEM 10* will be contained within the definitive ProxyStatement for the Company’s 2007 Annual Meeting of Shareholders (the “ProxyStatement”) under the headings “Election of Directors,” “Meetings andCommittees of the Board” and “Compliance with Section 16(a) of the Exchange Act”and is incorporated herein by reference. The Proxy Statement will be filed pursuant to Regulation 14A with theSecurities and Exchange Commission not later than 120 days after December 31,2006.  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.

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

***ITEM11.  EXECUTIVE COMPENSATION***

Theinformation required by *ITEM 11* will becontained in the Proxy Statement under the headings “Executive Compensation,” “Compensation Committee Interlocks and InsiderParticipation,” “Compensation Committee Report” and “2006 Director Compensation”and is incorporated herein by reference.

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

Theinformation required by *ITEM 12* will becontained in the Proxy Statement under the headings “Security Ownership ofCertain Beneficial Owners and Management” and “Equity Compensation PlanInformation” and is incorporated herein by reference.

***ITEM13.  CERTAIN RELATIONSHIPS AND RELATEDTRANSACTIONS, AND DIRECTOR INDEPENDENCE***

Theinformation required by *ITEM 13* will becontained in the Proxy Statement under the heading “Transactions with RelatedPersons” and is incorporated herein by reference.

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

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

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**PART IV**

***ITEM15.  EXHIBITS AND FINANCIAL STATEMENTSCHEDULES***
| (a)    | Financial Statements  and Schedules:                                           |
|--------|--------------------------------------------------------------------------------|
|   |                                                                           |   |
|   | 1.                                                                             | Financial Statements:  See Index to the Consolidated Financial  Statements and Supplementary Information immediately following the signature  page of this report. |
|   |                                                                           |   |   |   |
|   | 2.                                                                             | Financial Statement Schedule: See Index to the  Consolidated Financial Statements and Supplementary Information immediately  following the signature page of this report. |
|   |                                                                           |   |   |   |
| (b)    | Exhibits:  The  following documents are filed as exhibits to this report: |
|   |                                                                           |   |   |   |
|        | 2.1                                                                            | — |   | Amended and Restated Combination Agreement by and  among (i) Edge Group II Limited Partnership, (ii) Gulfedge Limited  Partnership, (iii) Edge Group Partnership, (iv) Edge Petroleum Corporation,  (v) Edge Mergeco, Inc. and (vi) the Company, dated as of January 13,  1997 (Incorporated by reference from exhibit 2.1 to the Company’s  Registration Statement on Form S-4 (Registration No. 333-17269)). |
|   |                                                                           |   |   |   |
|   | 2.2                                                                            | — |   | Agreement and Plan of Merger dated as of May 28,  2003 among Edge Petroleum Corporation, Edge Delaware Sub Inc. and Miller  Exploration Company (Miller”) (Incorporated by reference from Annex A to the  Joint Proxy Statement/Prospectus contained in the Company’s Registration  Statement on Form S-4/A filed on October 31, 2003 (Registration No.  333-106484)). |
|   |                                                                           |   |   |   |
|   | 2.3                                                                            | — |   | Asset Purchase Agreement by and among Contango STEP,  L.P., Contango Oil & Gas Company, Edge Petroleum Exploration Company and  Edge Petroleum Corporation, dated 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 (Incorporated by  reference from Exhibit 4.3 to the Company’s Annual Report on Form 10-K  for the year ended December 31, 2005 (File No. 000-22149)). |
|   |       |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
|   | 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)).                                                                                                                                                                                                                                                                                                                                                                              |
|   |       |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
|   | 4.8        | — |   | Fourth Amended and Restated Credit Agreement dated  January 31, 2007 by and among Edge Petroleum Corporation, as borrower, and  Union Bank of California, N.A., as Administrative Agent and Issuing Lender,  and the other lenders party thereto (Incorporated by reference from exhibit  4.1 to Edge’s Current Report on Form 8-K filed on February 5, 2007).                                                                                                                                                                                                                               |
|   |       |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
|   | †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)).                                                                                                                                                                                                                                                                                                                                                                                      |

 

65

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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   | — |   | Amended and Restated Incentive Plan of Edge  Petroleum Corporation as Amended and Restated Effective as of August 1, 2006  (Incorporated by reference from exhibit 10.4 to the Company’s Quarterly  Report on Form 10-Q for the six months ended June 30, 2006).                                                                  |
|   |         |   |   |                                                                                                                                                                                                                                                                                                                                   |
|   | †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 Certain Other Compensation of Executive  Officers.                                                                                                                                                                                                                                                                        |
|   |         |   |   |                                                                                                                                                                                                                                                                                                                                   |
|   | †10.14  | — |   | Description of Annual Cash Bonus Program for  Executive Officers (Incorporated by reference from Exhibit 10.2 to the  Company’s Current Report on Form 8-K filed March 12, 2007).                                                                                                                                            |
|   |         |   |   |                                                                                                                                                                                                                                                                                                                                   |
|   | †10.15  | — |   | New Base Salaries and Long-Term Incentive Awards for  Certain Executive Officers (Incorporated by reference from exhibit 10.1 to  the Company’s Current Report on Form 8-K filed August 25, 2006).                                                                                                                                |
|   |         |   |   |                                                                                                                                                                                                                                                                                                                                   |
|   | 10.16        | — |   | Purchase and Sale Agreement between Smith  Production, Inc., as seller, and Edge Petroleum Exploration Company, as  purchaser, dated November 16, 2006 (Incorporated by reference to exhibit 10.1  to Edge’s Current Report on Form 8-K filed January 16, 2007).                                                                  |
|   |         |   |   |                                                                                                                                                                                                                                                                                                                                   |
|   | 10.17        | — |   | Purchase and Sale Agreement between Smith  Production, Inc., as seller, and Edge Petroleum Exploration Company, as  purchaser, dated November 16, 2006 (Incorporated by reference to exhibit 10.2  to Edge’s Current Report on Form 8-K filed January 16, 2007).                                                                  |
|   |         |   |   |                                                                                                                                                                                                                                                                                                                                   |
|   | 10.18        | — |   | First Amendment of Purchase and Sale Agreement  between Smith Production, Inc., as seller, and Edge Petroleum Exploration  Company, as purchaser, dated December 15, 2006 (Incorporated by reference to  exhibit 10.3 to Edge’s Current Report on Form 8-K filed January 16, 2007).                                               |

 

66

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|        | 10.19  | — |   | Second Amendment of Purchase and Sale Agreement  between Smith Production, Inc., as seller, and Edge Petroleum Exploration  Company, as purchaser, dated January 15, 2007 (Incorporated by reference to  exhibit 10.1 to Edge’s Current Report on Form 8-K filed January 19, 2007).                                                               |
|--------|--------|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | 10.20  | — |   | First Amendment of Purchase and Sale Agreement  between Smith Production, Inc., as seller, and Edge Petroleum Exploration  Company, as purchaser, dated January 15, 2007 (Incorporated by reference to  exhibit 10.2 to Edge’s Current Report on Form 8-K filed January 19, 2007).                                                                |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | 10.21  | — |   | Third Amendment of Purchase and Sale Agreement  between Smith Production, Inc., as seller, and Edge Petroleum Exploration  Company, as purchaser, dated January 31, 2007 (Incorporated by reference to  exhibit 10.6 to Edge’s Current Report on Form 8-K filed February 7, 2007).                                                                |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | 10.22  | — |   | Certificate of Designations establishing the 5.75%  Series A cumulative convertible perpetual preferred stock, dated January 27,  2007 (Incorporated by reference to exhibit 3.1 to Edge’s Current Report on  Form 8-K filed January 30, 2007).                                                                                                   |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | 10.23  | — |   | Purchase and Sale Agreement between Kerr-McGee Oil  & Gas Onshore, L.P., as Seller, and Edge Petroleum Production Company, as  Purchaser, and Edge Petroleum Corporation, as Additional Purchaser dated  December 12, 2006 (Incorporated by reference from exhibit 2.1 to the  Company’s Current Report on Form 8-K filed December 18, 2006). |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | *12.1  | — |   | Statement of Computation of Ratio of Earnings to  Fixed Charges.                                                                                                                                                                                                                                                                                       |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | *21.1  | — |   | Subsidiaries of the Company.                                                                                                                                                                                                                                                                                                                           |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | *23.1  | — |   | Consent of BDO Seidman, LLP.                                                                                                                                                                                                                                                                                                                           |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | 23.2   | — |   | Consent of Ryder Scott Company (Incorporated by  reference from exhibit 23.1 to the Company’s Current Report on Form 8-K filed  January 23, 2007).                                                                                                                                                                                                |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | 23.3   | — |   | Consent of W. D. Von Gonten & Co. (Incorporated  by reference from exhibit 23.2 to the Company’s Current Report on Form 8-K  filed January 23, 2007).                                                                                                                                                                                         |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | *23.4  | — |   | Consent of Ryder Scott Company.                                                                                                                                                                                                                                                                                                                        |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | *31.1  | — |   | Certification by John W. Elias, Chief Executive  Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                   |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | *31.2  | — |   | Certification by Michael G. Long, Chief Financial  Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                 |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | *32.1  | — |   | Certification by John W. Elias, Chief Executive  Officer, pursuant to 18 USC Section 1350, as adopted pursuant to Section 906  of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                      |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | *32.2  | — |   | Certification by Michael G. Long, Chief Financial  Officer, pursuant to 18 USC Section 1350, as adopted pursuant to Section 906  of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                    |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | 99.1   | — |   | Summary of Reserve Report of Ryder Scott Company  Petroleum Engineers as of December 31, 2006 (Incorporated by reference from  exhibit 99.1 to the Company’s Current Report on Form 8-K filed January 23,  2007).                                                                                                                                 |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | 99.2   | — |   | Summary of Reserve Report of W. D. Von Gonten &  Co. Petroleum Engineers as of December 31, 2006 (Incorporated by reference  from exhibit 99.2 to the Company’s Current Report on Form 8-K filed January  23, 2007).                                                                                                                          |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
|   | 99.3   | — |   | Oversight review letter of Ryder Scott Company  Petroleum Engineers dated January 11, 2007 (Incorporated by reference from  exhibit 99.2 to the Company’s Current Report on Form 8-K filed January 16,  2007).                                                                                                                                    |

 

67

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|  | *99.4 | — |   | Supplemental Summary of Reserve Report of Ryder  Scott Company Petroleum Engineers as of December 31, 2006. |
|--|-------|--------|--------|-------------------------------------------------------------------------------------------------------------|

 

----

* Filed herewith.

† Denotes management orcompensatory contract, arrangement or agreement, or a summary or descriptionthereof.

68

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**SIGNATURES**

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

|        | **Edge Petroleum Corporation** |                                               |   |
|--------|--------------------------------|----------------------------------------------------|--------|
|   |                           |                                               |   |   |
|   | By                             | /S/ John W.  Elias                                 |   |   |
|   |                           | John W. Elias                                      |   |   |
|   |                           | Chief Executive  Officer and Chairman of the Board |   |   |
|   |                           | Date: March 12,  2007                              |   |   |

 

Pursuant to therequirements of the Securities Exchange Act of 1934, this report has beensigned below by the following persons on behalf of the registrant and in thecapacities and on the dates indicated.
| By     |   | /S/ John W.  Elias                                                                                            |   | Date: March 12, 2007 |   |
|--------|--------|---------------------------------------------------------------------------------------------------------------|--------|----------------------|--------|
|   |   | John W. Elias                                                                                                 |   |                 |   |
|   |   | Chief Executive  Officer and Chairman of the Board  (Principal Executive Officer)                             |   |                 |   |
|   |   |                                                                                                          |   |                 |   |
| By     |   | /S/ Michael G.  Long                                                                                          |   | Date: March 12, 2007 |   |
|   |   | Michael G. Long                                                                                               |   |                 |   |
|   |   | Executive Vice  President and Chief Financial Officer  (Principal Financial and Principal Accounting Officer) |   |                 |   |
|   |   |                                                                                                          |   |                 |   |
| By     |   | /S/ Thurmon M.  Andress                                                                                       |   | Date: March 12, 2007 |   |
|   |   | Thurmon Andress                                                                                               |   |                 |   |
|   |   | Director                                                                                                      |   |                 |   |
|   |   |                                                                                                          |   |                 |   |
| By     |   | /S/ Vincent S.  Andrews                                                                                       |   | Date: March 12, 2007 |   |
|   |   | Vincent Andrews                                                                                               |   |                 |   |
|   |   | Director                                                                                                      |   |                 |   |
|   |   |                                                                                                          |   |                 |   |
| By     |   | /S/ Jonathan  Clarkson                                                                                        |   | Date: March 12, 2007 |   |
|   |   | Jonathan  Clarkson                                                                                            |   |                 |   |
|   |   | Director                                                                                                      |   |                 |   |
|   |   |                                                                                                          |   |                 |   |
| By     |   | /S/ Michael A.  Creel                                                                                         |   | Date: March 12, 2007 |   |
|   |   | Michael A. Creel                                                                                         |   |                 |   |
|   |   | Director                                                                                                      |   |                 |   |
|   |   |                                                                                                          |   |                 |   |
| By     |   | /S/ Stanley S.  Raphael                                                                                       |   | Date: March 12, 2007 |   |
|   |   | Stanley S.  Raphael                                                                                           |   |                 |   |
|   |   | Director                                                                                                      |   |                 |   |
|   |   |                                                                                                          |   |                 |   |
| By     |   | /S/ John  Sfondrini                                                                                           |   | Date: March 12, 2007 |   |
|   |   | John Sfondrini                                                                                                |   |                 |   |
|   |   | Director                                                                                                      |   |                 |   |
|   |   |                                                                                                          |   |                 |   |
| By     |   | /S/ Robert W.  Shower                                                                                         |   | Date: March 12, 2007 |   |
|   |   | Robert W. Shower                                                                                              |   |                 |   |
|   |   | Director                                                                                                      |   |                 |   |
|   |   |                                                                                                          |   |                 |   |
| By     |   | /S/ David F.  Work                                                                                            |   | Date: March 12, 2007 |   |
|   |   | David F. Work                                                                                                 |   |                 |
|   |   | Director                                                                                                      |   |                 |

 

69

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

Index to Consolidated Financial Statements andSupplementary Information

**CONSOLIDATED FINANCIAL STATEMENTS**
| Audited Financial Statements:                                                                                  |   |   |
|----------------------------------------------------------------------------------------------------------------|--------|--------|
| Report  of Independent Registered Public Accounting Firm                                                       |   |   |
|                                                                                                           |   |   |
| Consolidated  Balance Sheets as of December 31, 2006 and 2005                                                  |   |   |
|                                                                                                           |   |   |
| Consolidated Statements of  Operations for the Years Ended   December 31, 2006, 2005 and 2004                  |   |   |
|                                                                                                           |   |   |
| Consolidated Statements of  Comprehensive Income (Loss) for the Years Ended   December 31, 2006, 2005 and 2004 |   |   |
|                                                                                                           |   |   |
| Consolidated Statements of  Cash Flows for the Years Ended   December 31, 2006, 2005 and 2004                  |   |   |
|                                                                                                           |   |   |
| Consolidated Statements of  Stockholders’ Equity for the Years Ended   December 31, 2006, 2005 and 2004   |   |   |
|                                                                                                           |   |   |
| Notes to  Consolidated Financial Statements                                                                    |   |   |
|                                                                                                           |   |   |
| Unaudited Information:                                                                                         |   |   |
| Supplementary  Information to Consolidated Financial Statements                                                |   |   |

                                                                                                          

**CONSOLIDATEDFINANCIAL STATEMENT SCHEDULES**

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

F-1

----

**Report of Independent Registered Public AccountingFirm**

Boardof Directors and StockholdersEdge Petroleum CorporationHouston, Texas

We have audited theaccompanying consolidated balance sheets of Edge Petroleum Corporation as ofDecember 31, 2006 and 2005 and the related consolidated statements ofoperations, comprehensive income (loss), stockholders’ equity, and cash flowsfor each of the three years in the period ended December 31, 2006.  These financial statements are theresponsibility of the Company’s management. Our responsibility is to express an opinion on these financialstatements based on our audits.

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

In our opinion, theconsolidated financial statements referred to above present fairly, in allmaterial respects, the financial position of Edge Petroleum Corporation atDecember 31, 2006 and 2005, and the results of its operations and its cashflows for each of the three years in the period ended December 31, 2006, inconformity with accounting principles generally accepted in the United Statesof America.

As discussed in Note 2 to the consolidatedfinancial statements, effective January 1, 2006 the Company adopted theprovisions of Statement of Financial Accounting Standards No. 123(R), “Share-BasedPayment”.

We also have audited, in accordance with the standardsof the Public Company Accounting Oversight Board (United States), theeffectiveness of Edge Petroleum Corporation’s internal control over financialreporting as of December 31, 2006, based on criteria established in *Internal Control – Integrated Framework*issuedby the Committee of Sponsoring Organizations of the Treadway Commission (COSO)and our report dated March 9, 2007 expressed an unqualified opinion thereon.
| /S/ BDO SEIDMAN, LLP |   |
|----------------------|--------|
|                 |
| BDO Seidman, LLP     |
|                 |
| Houston, Texas       |
| March 9, 2007        |

 

F-2

----

**EDGE PETROLEUM CORPORATION**

**CONSOLIDATED BALANCE SHEETS**
| ** **                                                                                                                                                                                                           | ** ** | **December 31,**                                     | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------|------------|
| ** **                                                                                                                                                                                                           | ** ** | **2006**                                                  | ** ** | **2005** | ** ** |
| ** **                                                                                                                                                                                                           | ** ** | **(in thousands, except share data)** | ** ** |
| **ASSETS**                                                                                                                                                                                                           |       |                                                      |       |   |   |
|                                                                                                                                                                                                                 |       |                                                      |       |   |   |
| CURRENT ASSETS:                                                                                                                                                                                                      |       |                                                      |       |   |   |
| Cash and cash  equivalents                                                                                                                                                                                           |       | $                                                         | 2,081      |   | $ | 666 |   |
| Accounts  receivable, trade, net of allowance                                                                                                                                                                        |       | 17,738                                                    |       | 24,980 |   |
| Accounts  receivable, joint interest owners and other, net of allowance                                                                                                                                              |       | 2,217                                                     |       | 2,100 |   |
| Deferred income  taxes                                                                                                                                                                                               |       | —                                                    |       | 2,518 |   |
| Derivative  financial instruments                                                                                                                                                                                    |       | 5,945                                                     |       | — |   |
| Other current  assets                                                                                                                                                                                                |       | 3,959                                                     |       | 6,437 |   |
|                                                                                                                                                                                                                 |       |                                                      |       |   |   |
| Total current  assets                                                                                                                                                                                                |       | 31,940                                                    |       | 36,701 |   |
|                                                                                                                                                                                                                 |       |                                                      |       |   |   |
| PROPERTY AND EQUIPMENT,  Net – full cost method of accounting for oil and natural gas properties  (including unevaluated costs of $57.6 million and $36.9 million at December  31, 2006 and 2005, respectively) |       | 289,457                                                   |       | 306,456 |   |
|                                                                                                                                                                                                                 |       |                                                      |       |   |   |
| OTHER ASSETS                                                                                                                                                                                                         |       | 260                                                       |       | 223 |   |
|                                                                                                                                                                                                                 |       |                                                      |       |   |   |
| TOTAL ASSETS                                                                                                                                                                                                         |       | $                                                         | 321,657    |   | $ | 343,380 |   |
|                                                                                                                                                                                                                 |       |                                                      |       |   |   |
| **LIABILITIES AND STOCKHOLDERS’  EQUITY**                                                                                                                                                                       |       |                                                      |       |   |   |
| ** **                                                                                                                                                                                                           |       |                                                      |       |   |   |
| CURRENT LIABILITIES:                                                                                                                                                                                                 |       |                                                      |       |   |   |
| Accounts  payable, trade                                                                                                                                                                                             |       | $                                                         | 3,953      |   | $ | 5,571 |   |
| Accrued  liabilities                                                                                                                                                                                                 |       | 16,638                                                    |       | 17,894 |   |
| Derivative  financial instruments                                                                                                                                                                                    |       | —                                                    |       | 2,479 |   |
| Accrued interest  payable                                                                                                                                                                                            |       | 541                                                       |       | 17 |   |
| Deferred income  taxes                                                                                                                                                                                               |       | 433                                                       |       | — |   |
| Asset retirement  obligation – current portion                                                                                                                                                                  |       | 213                                                       |       | 203 |   |
|                                                                                                                                                                                                                 |       |                                                      |       |   |   |
| Total current  liabilities                                                                                                                                                                                           |       | 21,778                                                    |       | 26,164 |   |
|                                                                                                                                                                                                                 |       |                                                      |       |   |   |
| ASSET RETIREMENT  OBLIGATION – long-term portion                                                                                                                                                                |       | 3,158                                                     |       | 2,564 |   |
|                                                                                                                                                                                                                 |       |                                                      |       |   |   |
| DERIVATIVE FINANCIAL  INSTRUMENTS                                                                                                                                                                                    |       | 758                                                       |       | — |   |
|                                                                                                                                                                                                                 |       |                                                      |       |   |   |
| DEFERRED TAX LIABILITY                                                                                                                                                                                               |       | 10,911                                                    |       | 37,897 |   |
|                                                                                                                                                                                                                 |       |                                                      |       |   |   |
| LONG-TERM DEBT                                                                                                                                                                                                       |       | 129,000                                                   |       | 85,000 |   |
|                                                                                                                                                                                                                 |       |                                                      |       |   |   |
| Total  liabilities                                                                                                                                                                                                   |       | 165,605                                                   |       | 151,625 |   |
|                                                                                                                                                                                                                 |       |                                                      |       |   |   |
| COMMITMENTS AND  CONTINGENCIES (Note 13)                                                                                                                                                                             |       |                                                      |       |   |   |
|                                                                                                                                                                                                                 |       |                                                      |       |   |   |
| 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; 17,442,229 and 17,216,776  shares issued and outstanding at December 31, 2006 and 2005, respectively                                                   |       | 174                                                       |       | 172 |   |
| Additional  paid-in capital                                                                                                                                                                                          |       | 141,685                                                   |       | 137,842 |   |
| Retained  earnings                                                                                                                                                                                                   |       | 14,193                                                    |       | 55,454 |   |
| Accumulated  other comprehensive loss                                                                                                                                                                                |       | —                                                    |       | (1,713 | ) |
|                                                                                                                                                                                                                 |       |                                                      |       |   |   |
| Total  stockholders’ equity                                                                                                                                                                                     |       | 156,052                                                   |       | 191,755 |   |
|                                                                                                                                                                                                                 |       |                                                      |       |   |   |
| TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY                                                                                                                                                                      |       | $                                                         | 321,657    |   | $ | 343,380 |   |

See accompanyingnotes to the consolidated financial statements.

F-3

----

**EDGE PETROLEUM CORPORATION**

**CONSOLIDATEDSTATEMENTS OF OPERATIONS**
| ** **                                                                        | ** **   | **Year Ended December 31,**                | ** **   |
|-----------------------------------------------------------------------------------|--------------|-----------------------------------------------------------|--------------|
| ** **                                                                        | ** **   | **2006**                                                  | ** **   | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                        | *** *** | **(in thousands, except share data)** | *** *** |
| OIL AND NATURAL GAS  REVENUE:                                                     |         |                                                      |         |   |   |   |   |
| Oil and natural  gas sales                                                        |         | $                                                         | 120,014      |   | $ | 123,450 |   | $ | 66,965 |   |
| Gain (loss) on  derivatives                                                       |         | 9,730                                                     |         | (2,267 | ) | (2,460 | ) |
| Total revenue                                                                     |         | 129,744                                                   |         | 121,183 |   | 64,505 |   |
|                                                                              |         |                                                      |         |   |   |   |   |
| OPERATING EXPENSES:                                                               |         |                                                      |         |   |   |   |   |
| Oil and natural  gas operating expenses including production and ad valorem taxes |         | 18,257                                                    |         | 17,068 |   | 9,309 |   |
| Depletion,  depreciation, amortization and accretion                              |         | 61,080                                                    |         | 40,218 |   | 21,928 |   |
| Impairment of  oil and natural gas properties                                     |         | 96,942                                                    |         | — |   | — |   |
| Bad debt expense                                                                  |         | —                                                    |         | 65 |   | — |   |
| General and  administrative expenses                                              |         | 13,788                                                    |         | 12,371 |   | 9,447 |   |
|                                                                              |         |                                                      |         |   |   |   |   |
| Total operating  expenses                                                         |         | 190,067                                                   |         | 69,722 |   | 40,684 |   |
|                                                                              |         |                                                      |         |   |   |   |   |
| OPERATING INCOME (LOSS)                                                           |         | (60,323                                                   | )            | 51,461 |   | 23,821 |   |
|                                                                              |         |                                                      |         |   |   |   |   |
| OTHER INCOME (EXPENSE):                                                           |         |                                                      |         |   |   |   |   |
| Interest  expense, net of amounts capitalized                                     |         | (2,500                                                    | )            | — |   | (331 | ) |
| Amortization of  deferred loan costs                                              |         | (165                                                      | )            | (153 | ) | (142 | ) |
| Interest income                                                                   |         | 152                                                       |         | 128 |   | 36 |   |
|                                                                              |         |                                                      |         |   |   |   |   |
| INCOME (LOSS) BEFORE  INCOME TAXES                                                |         | (62,836                                                   | )            | 51,436 |   | 23,384 |   |
|                                                                              |         |                                                      |         |   |   |   |   |
| INCOME TAX (EXPENSE)  BENEFIT                                                     |         | 21,575                                                    |         | (18,078 | ) | (8,255 | ) |
|                                                                              |         |                                                      |         |   |   |   |   |
| NET INCOME (LOSS)                                                                 |         | $                                                         | (41,261      | ) | $ | 33,358 |   | $ | 15,129 |   |
|                                                                              |         |                                                      |         |   |   |   |   |
| BASIC EARNINGS (LOSS)  PER SHARE                                                  |         | $                                                         | (2.38        | ) | $ | 1.95 |   | $ | 1.16 |   |
|                                                                              |         |                                                      |         |   |   |   |   |
| DILUTED EARNINGS (LOSS)  PER SHARE                                                |         | $                                                         | (2.38        | ) | $ | 1.87 |   | $ | 1.11 |   |
|                                                                              |         |                                                      |         |   |   |   |   |
| BASIC WEIGHTED AVERAGE  NUMBER OF COMMON SHARES OUTSTANDING                       |         | 17,368                                                    |         | 17,122 |   | 13,029 |   |
|                                                                              |         |                                                      |         |   |   |   |   |
| DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING                      |         | 17,368                                                    |         | 17,815 |   | 13,648 |   |

 

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

F-4

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**EDGE PETROLEUM CORPORATION**

**CONSOLIDATEDSTATEMENTS OF COMPREHENSIVE INCOME (LOSS)**
| ** **                                                                  | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                  | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                  | ** ** | **(in thousands)**                    | ** ** |
|                                                                        |       |                                       |       |   |   |   |   |
| NET INCOME (LOSS)                                                           |       | $                                          | (41,261    | ) | $ | 33,358 |   | $ | 15,129 |   |
|                                                                        |       |                                       |       |   |   |   |   |
| OTHER COMPREHENSIVE  INCOME (LOSS), net of tax:                             |       |                                       |       |   |   |   |   |
| Change in fair  value of outstanding hedging and derivative instruments (1) |       | —                                     |       | (3,761 | ) | 953 |   |
| Reclassification  of hedging and derivative losses (2)                      |       | 1,713                                      |       | 799 |   | 660 |   |
| Other  comprehensive income (loss)                                          |       | 1,713                                      |       | (2,962 | ) | 1,613 |   |
|                                                                        |       |                                       |       |   |   |   |   |
| COMPREHENSIVE INCOME  (LOSS)                                                |       | $                                          | (39,548    | ) | $ | 30,396 |   | $ | 16,742 |   |
|                                                                        |       |                                       |       |   |   |   |   |
| (1) net of income taxes                                                     |       | $                                          | —     |   | $ | (2,025 | ) | $ | 513 |   |
| (2) net of income taxes                                                     |       | $                                          | 922        |   | $ | 430 |   | $ | 355 |   |

 

Seeaccompanying notes to the consolidated financial statements**.**

 

F-5

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**EDGE PETROLEUM CORPORATION**

**CONSOLIDATEDSTATEMENTS OF CASH FLOWS**
| ** **                                                                                | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                                | ** ** | **(in thousands)**                    | ** ** |
| CASH FLOWS FROM  OPERATING ACTIVITIES:                                                    |       |                                       |       |   |   |   |   |
| Net income  (loss)                                                                        |       | $                                          | (41,261    | ) | $ | 33,358 |   | $ | 15,129 |   |
| Adjustments to  reconcile net income (loss) to net cash provided by operating activities: |       |                                       |       |   |   |   |   |
| Unrealized  (gain) loss on the fair value of derivatives                                  |       | (5,031                                     | )          | (720 | ) | 565 |   |
| Loss on property                                                                          |       | —                                     |       | 2 |   | — |   |
| Depletion,  depreciation, amortization and accretion                                      |       | 61,080                                     |       | 40,218 |   | 21,928 |   |
| Impairment of  oil and natural gas properties                                             |       | 96,942                                     |       | — |   | — |   |
| Amortization of  deferred loan costs                                                      |       | 165                                        |       | 153 |   | 142 |   |
| Deferred tax  provision                                                                   |       | (21,575                                    | )          | 18,078 |   | 8,255 |   |
| Non-cash  share-based compensation cost                                                   |       | 2,807                                      |       | 2,769 |   | 1,746 |   |
| Bad debt expense                                                                          |       | —                                     |       | 65 |   | — |   |
| Changes in  operating assets and liabilities:                                             |       |                                       |       |   |   |   |   |
| (Increase)  decrease in accounts receivable, trade                                        |       | 7,242                                      |       | (9,770 | ) | (3,180 | ) |
| (Increase)  decrease in accounts receivable, joint interest owners                        |       | (117                                       | )          | 3,746 |   | (4,113 | ) |
| Increase in  other assets                                                                 |       | (536                                       | )          | (1,062 | ) | (259 | ) |
| Increase  (decrease) in accounts payable, trade                                           |       | (1,618                                     | )          | 2,052 |   | 1,408 |   |
| Increase in  accrued interest payable                                                     |       | 524                                        |       | 17 |   | — |   |
| Increase  (decrease) in accrued liabilities                                               |       | (1,213                                     | )          | 4,205 |   | 649 |   |
| Net cash  provided by operating activities                                                |       | 97,409                                     |       | 93,111 |   | 42,270 |   |
|                                                                                      |       |                                       |       |   |   |   |   |
| CASH FLOWS FROM  INVESTING ACTIVITIES:                                                    |       |                                       |       |   |   |   |   |
| Capital  expenditures                                                                     |       | (144,338                                   | )          | (123,959 | ) | (89,470 | ) |
| Drilling  advances                                                                        |       | 2,869                                      |       | (4,286 | ) | — |   |
| Proceeds from  the sale of oil and natural gas properties                                 |       | 628                                        |       | — |   | 60 |   |
| Acquisition of  Cinco Energy Corporation, net of cash acquired                            |       | 429                                        |       | (39,035 | ) | — |   |
| Net cash used in  investing activities                                                    |       | (140,412                                   | )          | (167,280 | ) | (89,410 | ) |
|                                                                                      |       |                                       |       |   |   |   |   |
| CASH FLOWS FROM FINANCING  ACTIVITIES:                                                    |       |                                       |       |   |   |   |   |
| Borrowings from  long-term debt                                                           |       | 62,000                                     |       | 81,000 |   | 27,000 |   |
| Payments on  long-term debt                                                               |       | (18,000                                    | )          | (16,000 | ) | (28,000 | ) |
| Net proceeds  from issuance of common stock                                               |       | 576                                        |       | 7,615 |   | 49,507 |   |
| Deferred loan  costs                                                                      |       | (158                                       | )          | (47 | ) | (427 | ) |
| Net cash  provided by financing activities                                                |       | 44,418                                     |       | 72,568 |   | 48,080 |   |
|                                                                                      |       |                                       |       |   |   |   |   |
| NET INCREASE (DECREASE)  IN CASH AND CASH EQUIVALENTS                                     |       | 1,415                                      |       | (1,601 | ) | 940 |   |
| CASH AND CASH  EQUIVALENTS, BEGINNING OF YEAR                                             |       | 666                                        |       | 2,267 |   | 1,327 |   |
| CASH AND CASH EQUIVALENTS, END OF YEAR                                                    |       | $                                          | 2,081      |   | $ | 666 |   | $ | 2,267 |   |

 

See accompanying notes to theconsolidated financial statements.

F-6

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**EDGEPETROLEUM CORPORATION**

**CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY**
| ** **                                                           | ** ** | **Common Stock**   | ** ** | **Additional** | ** ** | **Retained**             | ** ** | **Accumulated  Other  Comprehensive** | ** ** | **Total  Stockholders’ ** | ** ** |
|----------------------------------------------------------------------|------------|-------------------------|------------|----------------|------------|--------------------------|------------|---------------------------------------|------------|-------------------------------------|------------|
| ** **                                                           | ** ** | **Shares**              | ** ** | **Amount**     | ** ** | **Paid-in Capital** | ** ** | **Earnings**                          | ** ** | **Income (Loss)**              | ** ** | **Equity** | ** ** |
| ** **                                                           | ** ** | **(in thousands)** | ** ** |
| **BALANCE, DECEMBER 31, 2003**                                       |       | 12,581                  |       | $              | 126        |                     | $          | 75,282                                |       | $                                   | 6,967      |   | $ | (364 | ) | $ | 82,011 |   |
| Issuance of  common stock                                            |       | 3,955                   |       | 39             |       | 49,579                   |       | —                                |       | —                              |       | 49,618 |   |
| Compensation  cost – restricted stock                           |       | —                  |       | —         |       | 498                      |       | —                                |       | —                              |       | 498 |   |
| Compensation  cost – repriced options                           |       | —                  |       | —         |       | 1,136                    |       | —                                |       | —                              |       | 1,136 |   |
| Tax benefit  associated with exercise of non-qualified stock options |       | —                  |       | —         |       | 462                      |       | —                                |       | —                              |       | 462 |   |
| Change in  valuation of hedging instruments                          |       | —                  |       | —         |       | —                   |       | —                                |       | 1,613                               |       | 1,613 |   |
|                                                                 |       |                    |       |           |       |                     |       |                                  |       |                                |       |   |   |
| Net income                                                           |       | —                  |       | —         |       | —                   |       | 15,129                                |       | —                              |       | 15,129 |   |
| **BALANCE, DECEMBER 31, 2004**                                       |       | 16,536                  |       | 165            |       | 126,957                  |       | 22,096                                |       | 1,249                               |       | 150,467 |   |
| Issuance of  common stock                                            |       | 681                     |       | 7              |       | 7,776                    |       | —                                |       | —                              |       | 7,783 |   |
| Compensation  cost – restricted stock                           |       | —                  |       | —         |       | 974                      |       | —                                |       | —                              |       | 974 |   |
| Compensation  cost – repriced options                           |       | —                  |       | —         |       | 1,628                    |       | —                                |       | —                              |       | 1,628 |   |
| Tax benefit  associated with exercise of non-qualified stock options |       | —                  |       | —         |       | 507                      |       | —                                |       | —                              |       | 507 |   |
| Change in  valuation of hedging instruments                          |       | —                  |       | —         |       | —                   |       | —                                |       | (2,962                              | )          | (2,962 | ) |
|                                                                 |       |                    |       |           |       |                     |       |                                  |       |                                |       |   |   |
| Net income                                                           |       | —                  |       | —         |       | —                   |       | 33,358                                |       | —                              |       | 33,358 |   |
| **BALANCE, DECEMBER 31, 2005**                                       |       | 17,217                  |       | 172            |       | 137,842                  |       | 55,454                                |       | (1,713                              | )          | 191,755 |   |
| Issuance of  common stock                                            |       | 225                     |       | 2              |       | 1,404                    |       | —                                |       | —                              |       | 1,406 |   |
| Compensation  cost – restricted stock                           |       | —                  |       | —         |       | 1,908                    |       | —                                |       | —                              |       | 1,908 |   |
| Compensation  cost – stock option expense                       |       | —                  |       | —         |       | 69                       |       | —                                |       | —                              |       | 69 |   |
| Tax benefit  associated with exercise of non-qualified stock options |       | —                  |       | —         |       | 462                      |       | —                                |       | —                              |       | 462 |   |
| Change in  valuation of hedging instruments                          |       | —                  |       | —         |       | —                   |       | —                                |       | 1,713                               |       | 1,713 |   |
|                                                                 |       |                    |       |           |       |                     |       |                                  |       |                                |       |   |   |
| Net loss                                                             |       | —                  |       | —         |       | —                   |       | (41,261                               | )          | —                              |       | (41,261 | ) |
| **BALANCE, DECEMBER 31, 2006**                                       |       | 17,442                  |       | $              | 174        |                     | $          | 141,685                               |       | $                                   | 14,193     |   | $ | — |   | $ | 156,052 |   |

 

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 Delawarecorporation in August 1996 in connection with its initial public offering andthe related combination of certain entities that held interests in Edge JointVenture II (the “Joint Venture”) and certain other oil and natural gasproperties; herein referred to as the “Combination”.  In a series of transactions the Companyissued an aggregate of 4,701,361 shares of common stock and received inexchange 100% of the ownership interests in the Joint Venture and certain otheroil and natural gas properties.  In March1997, and contemporaneously with the Combination, the Company completed theinitial public offering of 2,760,000 shares of its common stock (the “Offering”).In December 2003, the Company completed a merger with Miller ExplorationCompany (“Miller”) in a stock for stock transaction, in which the Companyissued 2.6 million shares of common stock to the shareholders of Miller. InDecember 2004 and January 2005, the Company completed a public offering ofcommon stock in which 4.0 million shares were issued in order to fund the assetacquisition from Contango Oil & Gas Company (“Contango”). In November 2005,the Company acquired 100% of the stock of Cinco Energy Corporation (“Cinco”),which continues as a wholly owned subsidiary named Edge Petroleum ProductionCompany (see Note 6).

***Nature of Operations -*****The Company is an independent energy company engaged in theexploration, development, acquisition and production of oil and natural gas.The Company’s resources and assets are managed and its results are reported asone operating segment. The Company conducts its operations primarily along theonshore United States Gulf Coast, with its primary emphasis in south Texas,Mississippi, Arkansas, Louisiana and Southeast New Mexico. In its explorationefforts the Company emphasizes an integrated geologic interpretation method incorporating3-D seismic technology and advanced visualization and data analysis techniquesutilizing state-of-the-art computer hardware and software.

**2.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES**

***Principles of Consolidation -*** Theconsolidated financial statements include the accounts of all majority ownedsubsidiaries of the Company, including Edge Petroleum Operating Company Inc.,Edge Petroleum Exploration Company, Edge Petroleum Production Company (formerlyCinco Energy Corporation), Miller Oil Corporation, and Miller ExplorationCompany, which are 100% owned subsidiaries of the Company. All intercompanybalances and transactions have been eliminated in consolidation.

***Changes inAccounting Principles******–*** Beginning January 1, 2006, the Company adopted the provisions ofStatement of Financial Accounting Standards (“SFAS”) No. 123(R), *Share-Based Payment*. This statement requires the Company to record expense associated withthe fair value of stock-based compensation. The Company elected to use the modified-prospective adoption method forthe standard which is discussed in further detail below and in Note 17.

***Cash and Cash Equivalents -***The Company considers all highly liquid investments with original maturities ofthree months or less to be cash equivalents.

***Financial Instruments -***The Company’s financial instruments consist of cash, receivables, payables,long-term debt and oil and natural gas commodity derivatives.  The carrying amount of cash, receivables andpayables approximates fair value because of the short-term nature of theseitems.  The carrying amount of long-termdebt as of December 31, 2006 and 2005 approximates fair value because theinterest rates are variable and reflective of market rates. Derivative instrumentsare reflected at fair value based on quotes obtained from our counterparties.

***Revenue Recognition -*** TheCompany recognizes oil and natural gas revenue from its interests in producingwells as oil and natural gas is produced and sold from those wells.  Oil and natural gas sold by the Company isnot significantly different from the Company’s share of production.

***Allowance for Doubtful Accounts******-*** The Company routinely assesses therecoverability of all material trade and other receivables to determine itsability to collect the receivables in full. Many of the Company’s receivablesare from joint interest owners on properties of which the Company is theoperator. Thus, the Company may have the ability to withhold future revenuedisbursements to recover any non-payment of joint interest billings.  Generally,

F-8

----

the Company’s crude oiland natural gas receivables are collected within two to three months. TheCompany accrues a reserve on a receivable when, based on the judgment ofmanagement, it is probable that a receivable will not be collected and theamount of any reserve may be reasonably estimated (see Note 3).

***Inventories -***Inventories consist principally of tubulargoods and production equipment, stated at the lower of weighted-average cost ormarket.

***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 one to sevenyears.

***Oiland Natural Gas Properties -*** The accounting for our business issubject to special accounting rules that are unique to the oil and gasindustry. There are two allowable methods of accounting for oil and gasbusiness activities:  thesuccessful-efforts method 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.  The Company utilizes thefull-cost method of accounting for oil and natural gas properties.  In accordance with the full-cost method ofaccounting, all costs associated with the exploration, development andacquisition of oil and natural gas properties, including salaries, benefits andother internal costs directly attributable to these activities are capitalizedwithin a cost center. The Company’s oil and natural gas properties are locatedwithin the United States of America, which constitutes one cost center.  The Company also capitalizes a portion ofinterest expense on borrowed funds.

In the measurement ofimpairment of proved oil and gas properties, the successful-efforts method ofaccounting follows the guidance provided in 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.  The full-cost method follows guidanceprovided in Securities and Exchange Commission (“SEC”) Regulation S-X Rule4-10, where impairment is determined by the “ceiling test,” whereby to theextent that such capitalized costs subject to amortization in the full costpool (net of depletion, depreciation and amortization and related deferredtaxes) exceed the present value (using 10% discount rate) of estimated futurenet after-tax cash flows from proved oil and natural gas reserves adjusted forasset retirement obligations net of salvage value, such excess costs arecharged to expense.  Once incurred, animpairment of oil and natural gas properties is not reversible at a laterdate.  A ceiling test impairment couldresult in a significant loss for a reporting period; however, future depletionexpense would be correspondingly reduced. In accordance with SEC Staff Accounting Bulletin (“SAB”) No. 103, *Update of Codification of Staff Accounting Bulletins*,derivative instruments qualifying as cash flow hedges are to be included in thecomputation of limitation on capitalized costs. During the first quarter of2006, the Company discontinued the use of cash flow hedge accounting;therefore, the ceiling test at December 31, 2006 was not impacted by the valueof our derivatives.  At December 31, 2005and 2004, the Company was applying cash flow hedge accounting to its naturalgas derivatives, and the period-end price was between the cap and floorestablished by the Company’s hedge contracts and thus no impact was included inthe ceiling test calculation.

Impairment of oil and natural gas properties isassessed quarterly in conjunction with the Company’s quarterly and annual SECfilings. The Company recorded a non-cash ceiling test impairment of oil andnatural gas properties for the year ended December 31, 2006 of $96.9 million($63.0 million net of tax).  Theimpairment was recorded in the third quarter of 2006 and was primarily theresult of a decline in natural gas prices at September 30, 2006.  At December 31, 2005, the quoted marketprices, adjusted for differentials, utilized in calculating the full-costceiling were $10.05 per MMBtu for natural gas and $61.04 per barrel for crudeoil.  Our impairment of $96.9 million atSeptember 30, 2006 was calculated based upon prices of $4.18 per MMBtu fornatural gas and $62.92 per barrel for crude oil.  Subsequent to the end of the reportingperiod, quoted market prices for natural gas increased such that we believe wewould have avoided a write-down if, as would have been allowed under applicableaccounting guidelines, we had elected to use such subsequent prices incalculating the ceiling test at September 30, 2006.  No ceiling test impairment was required duringthe comparable 2005 and 2004 period.

The Company capitalized $3.0 million, $2.6 million,and $2.2 million of general and administrative costs in 2006, 2005 and 2004,respectively. The Company also capitalizes a portion of interest expense onborrowed funds

F-9

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relatedto unproved oil and gas properties. The Company capitalized approximately $5.3million, $1.9 million, and $0.7 million of interest costs in 2006, 2005 and2004, respectively.

Oil and natural gas properties are amortized using theunit-of-production method using estimates of proved reserve quantities.  Investments in unproved properties are notamortized until proved reserves associated with the prospects can be determinedor until impairment occurs. Unproved oil and natural gas properties consist ofthe cost of unevaluated leaseholds, cost of seismic data, exploratory anddevelopmental wells in progress, and secondary recovery projects before theassignment of proved reserves. Oil and natural gas properties include costs of$57.6 million and $36.9 million at December 31, 2006 and 2005, respectively,related to unproved property, which were excluded from capitalized costs beingamortized. Unproved properties are evaluated quarterly, and as needed, forimpairment on a property-by-property basis. Factors considered by management inits impairment assessment include drilling results by the Company and otheroperators, the terms of oil and natural gas leases not held by production,production response to secondary recovery activities and available funds forexploration and development. If the results of an assessment indicate that anunproved property is impaired, the amount of impairment is added to the provedoil and natural gas property costs to be amortized. In September 2004, the SECissued SAB No. 106, *Interaction of Statement143 and the Full Cost Rules,* which the Company adopted in the fourthquarter of 2004 with no impact on the Company’s financial statements. Inaccordance with SAB No. 106*,*theamortizable base used to calculate unit-of-production depletion includesestimated future development and dismantlement costs, and restoration andabandonment costs, net of estimated salvage values. The depletion rates perMcfe for the years ended December 31, 2006, 2005 and 2004 were $3.51, $2.43,and $1.78, respectively.

Sales of proved and unproved properties are accountedfor as adjustments of capitalized costs with no gain or loss recognized, unlesssuch adjustments would significantly alter the relationship between capitalizedcosts and proved reserves.

***Asset Retirement Obligations –***TheCompany accounts for asset retirement obligations under the provisions of SFASNo. 143, *Accounting for Asset RetirementObligations,*which provides for an asset and liability approach toaccounting for Asset Retirement Obligations (“ARO”). Under this method, whenlegal obligations for dismantlement and abandonment costs, excluding salvagevalues, are incurred, a liability is recorded at fair value and the carryingamount of the related oil and gas properties is increased. Accretion of theliability is recognized each period using the interest method of allocation andthe capitalized cost is depleted over the useful life of the related asset. Seefurther discussion in Note 7.

***Income Taxes******-*** TheCompany accounts for income taxes under the provisions of SFAS No. 109, *Accounting for Income Taxes*, whichprovides for an asset and liability approach to accounting for incometaxes.  Under this approach, deferred taxassets and liabilities are recognized based on anticipated future taxconsequences, using currently enacted tax laws, attributable to differencesbetween financial statement carrying amounts of assets and liabilities andtheir respective tax bases (see Note 15).

***Earningper Share***- The Company accounts for earnings per share in accordancewith SFAS No. 128, *Earnings per Share*,which establishes the presentation requirements for earnings per share (“EPS”).  SFAS No. 128 requires the presentation of “basic”and “diluted” EPS on the face of the statement of operations.  Basic earnings per common share amounts arecalculated using the weighted average number of common shares outstandingduring each period.  Diluted earnings percommon share assumes the exercise of all restricted stock units, stock optionsand warrants having exercise prices less than the average market price of thecommon stock during the periods, using the treasury stock method.

The following is areconciliation of the numerators and denominators of basic and diluted earningsper common share computations, in accordance with SFAS No. 128, for the yearsended December 31, 2006, 2005 and 2004:

F-10

----

 
|                                                    | ** ** | **Year Ended December 31,**                            | ** ** |
|----------------------------------------------------|------------|-----------------------------------------------------------------------|------------|
| ** **                                         | ** ** | **2006**                                                              | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                         | ** ** | **(in thousands, except per share amounts)** | ** ** |
| ** **                                         | ** ** | ** **                                                            | ** ** |
| Net income  (loss)                                 |       | $                                                                     | (41,261    | ) | $ | 33,358 |   | $ | 15,129 |   |
|                                               |       |                                                                  |       |   |   |   |   |
| Basic weighted average shares outstanding          |       | 17,368                                                                |       | 17,122 |   | 13,029 |   |
| Add: dilutive effect of employee stock options     |       | —                                                                |       | 498 |   | 477 |   |
| Add: dilutive effect of restricted stock units     |       | —                                                                |       | 195 |   | 142 |   |
| Diluted weighted-average common shares outstanding |       | 17,368                                                                |       | 17,815 |   | 13,648 |   |
|                                               |       |                                                                  |       |   |   |   |   |
| Basic income (loss) per common share               |       | $                                                                     | (2.38      | ) | $ | 1.95 |   | $ | 1.16 |   |
| Diluted income (loss) per common share             |       | $                                                                     | (2.38      | ) | $ | 1.87 |   | $ | 1.11 |   |

 

Due to the Company’s netloss in 2006 our unvested restricted stock units and stock options (429,567equivalent shares) were not included in computing diluted earnings per sharebecause the effect was antidilutive.  Incomputing earnings per share, no adjustments were made to reported net income(loss).

***Share-BasedCompensation –***At December 31, 2006,the Company had a share-based employee compensation plan that includedrestricted stock units and stock options issued to employees and non-employeedirectors, as more fully described in Note 17. Stock options were last issued in April 2004.  Prior to 2006, the Company accounted forshare-based compensation using the intrinsic value recognition and measurementprinciples detailed in Accounting Principles Board (“APB”) Opinion No. 25, *Accounting for Stock Issued to Employees* and related interpretations.  Except for certain repriced options describedbelow, no share-based compensation expense relating to stock option grants wasreflected in the Company’s consolidated statements of operations for any periodpresented prior to 2006, since all options granted under the plans had anexercise price equal to the market value of the underlying common stock on thedate of grant.  The Company used theBlack-Scholes option calculation model to calculate the disclosures requiredunder SFAS No. 123, *Accounting for Stock BasedCompensation*.  In 1999, theCompany repriced certain employee and director stock options.  The Company accounted for these repricedstock options in accordance with Financial Accounting Standards Board (“FASB”)Interpretation No. 44 (“FIN 44”), *Accounting for CertainTransactions involving Stock Based Compensation – An Interpretation of APB No.25*, which prescribed the variable plan accounting treatment forrepriced options.  Under variable planaccounting, compensation expense is adjusted for increases or decreases in thefair market value of the Company’s common stock to the extent that the marketvalue exceeds the exercise price of the option until the options are exercised,forfeited, or expire unexercised. Beginning January 1, 2006, the Company adopted the provisions of SFASNo. 123(R), *Share-Based Payment*.  This statement requires the Company to recordexpense associated with the fair value of share-based compensation.  The Company elected to use themodified-prospective adoption method for the standard and has consequentlyrecognized additional compensation expense of $68,937 in 2006.  No further expense associated with stockoptions is expected to be recognized unless future awards are granted.  The Company has recorded compensation expenseassociated with the issuance of restricted stock and restricted stock unitssince the plan was adopted in 1997 and stock or stock units were firstgranted.  The Company recognizes costsassociated with these grants based on the estimated fair value of therestricted stock units as determined at the time of grant.

Thefollowing table illustrates the effect on net income and earnings per shareinformation if the Company had applied the fair value recognition provision ofSFAS No. 123(R) to options and restricted stock units granted under ourshare-based compensation plans in 2005 and 2004.  For the purposes of this pro formadisclosure, the value is estimated using a Black-Scholes option-pricing formulaand expensed over the option’s vesting periods.

F-11

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|                                                                                                     | ** ** | **Year Ended December 31,**                        | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                                                                                          | ** ** | **2005**                                                          | ** ** | **2004** | ** ** |
| ** **                                                                                          | ** ** | **(in thousands, except per share  amounts)** | ** ** |
| Net income:                                                                                         |       |                                                              |       |   |   |
| As reported                                                                                         |       | $                                                                 | 33,358     |   | $ | 15,129 |   |
| Add: share-based employee compensation reported in  net income, net of taxes                        |       | 1,691                                                             |       | 1,062 |   |
| Deduct: share-based employee compensation under the  fair value method for all awards, net of taxes |       | (822                                                              | )          | (608 | ) |
| Pro forma net  income                                                                               |       | $                                                                 | 34,227     |   | $ | 15,583 |   |
|                                                                                                |       |                                                              |       |   |   |
| Earnings per  share:                                                                                |       |                                                              |       |   |   |
| Basic - as reported                                                                                 |       | $                                                                 | 1.95       |   | $ | 1.16 |   |
| Basic – pro forma                                                                              |       | 2.00                                                              |       | 1.20 |   |
| Diluted – as reported                                                                          |       | 1.87                                                              |       | 1.11 |   |
| Diluted – pro  forma                                                                           |       | 1.95                                                              |       | 1.16 |   |

 

***Derivativesand Hedging Activities -*****The Company accounts for its derivativecontracts under the provisions of SFAS No. 133, *Accounting for Derivative Instruments and Hedging Activities*(as amended).  The statement requiresthat all derivatives be recognized as either assets or liabilities and measuredat fair value, and changes in the fair value of derivatives be reported incurrent earnings, unless the derivative qualifies for special hedge accountingtreatment. If the derivative is designated as a cash flow hedge and theintended use of the derivative is to hedge the exposure to variability inexpected future cash flows, then the changes in the fair value of thederivative instrument will generally be 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.  If hedge accounting is discontinued becauseit is probable that a forecasted transaction will not occur, the derivativewill continue to be carried on the balance sheet at its fair value and gainsand losses that were accumulated in other comprehensive income will berecognized in earnings immediately.  Duringthe first quarter of 2006, the Company determined that the cash flow hedgeaccounting treatment previously applied to its natural gas contracts should bediscontinued due to projected changes in the 2006 physical production volumeshedged and to give the Company more flexibility in how it markets its physicalproduction. In 2006, the Company applied mark-to-market accounting treatment toall outstanding derivative contracts. Therefore, the changes in fair value are not deferred through othercomprehensive income, but rather recorded in revenue immediately as unrealizedgains or losses. Going forward, the Company will continue to evaluate the termsof new contracts entered into to determine whether cash flow hedge accountingtreatment or mark-to-market accounting treatment will be applied. In the past,the Company has used mark-to-market accounting treatment for its crude oilcontracts and cash flow hedge accounting treatment for its natural gascontracts, therefore unrealized gains and losses on the change in fair value ofnatural gas contracts between periods may not be comparable.  (See Note 9).

***Comprehensive Income -***The Company follows theprovisions of SFAS No. 130, *ReportingComprehensive Income*. SFAS No. 130 establishes standards forreporting and presentation of comprehensive income and its components. SFAS No.130 requires that all items that are required to be recognized under accountingstandards as components of comprehensive income be reported in a financialstatement that is displayed with the same prominence as other financialstatements. In accordance with the provisions of SFAS No. 130, the Company haspresented the components of comprehensive income on the face of theconsolidated statements of comprehensive income. For the years ended December31, 2005 and 2004, the only component of other comprehensive income was changesin fair value of hedging instruments and reclassifications of hedging gains andlosses.  This component of othercomprehensive income is not applicable in 2006 because cash flow hedgeaccounting was discontinued in the first quarter of the year.

***Use of Estimates -***The preparation of financial statements in conformity with accountingprinciples generally accepted in the United States of America requiresmanagement to make estimates and assumptions that affect the reported amountsof assets and liabilities and disclosure of contingent assets and liabilitiesas of the date of the financial statements and the reported amounts of revenuesand expenses during the reporting periods. Actual results 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 abandonmentobligations, impairment of undeveloped properties, future income taxes andrelated assets/liabilities, bad debts, derivatives, contingencies andlitigation. Oil and natural gas reserve estimates, which are the basis forunit-of-production depletion and the ceiling test, have numerous inherentuncertainties. The accuracy of any reserve estimate is a function of thequality of available data and of engineering and geological interpretation andjudgment.  Results of drilling, testing,and production subsequent to the date of the estimate may justify revision ofsuch estimate.  Accordingly, reserveestimates are often different

F-12

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from thequantities of oil and natural gas that are ultimately recovered. In addition,reserve estimates are vulnerable to changes in wellhead prices of crude oil andnatural gas. Such prices have been volatile in the past and can be expected tobe volatile in the future.

***Concentration of Credit Risk -***Substantiallyall of the Company’s accounts receivable result from oil and natural gas salesor joint interest billings to third parties in the oil and natural gasindustry.  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, theCompany has not experienced significant credit losses on such receivables;however, in 2001, the Company reserved $0.5 million related to non-payments fromtwo purchasers of the Company’s oil and natural gas, which remains in theallowance for doubtful accounts receivable, trade until such time as theCompany discontinues pursuing recovery efforts. In 2006, the Company wrote off$1,571 in accounts receivable from joint interest owners.  During 2005 the Company recorded $65,157 ofbad debt expense to increase its allowance for outstanding receivables fromjoint interest owners and wrote off $142,386 in accounts receivable from jointinterest owners.  No bad debt expense wasrecorded in 2004 related to joint interest owners.  The Company cannot ensure that similar suchlosses may not be realized in the future.

***Recently Issued Accounting Pronouncements******–*** In March 2006,the FASB issued SFAS No. 156, *Accounting for Servicingof Financial Assets*, which requires all separately recognizedservicing assets and servicing liabilities be initially measured at fair value.SFAS No. 156 permits, but does not require, the subsequent measurement ofservicing assets and servicing liabilities at fair value. Adoption is requiredas of the beginning of the first fiscal year that begins afterSeptember 15, 2006. Early adoption is permitted. The adoption of SFAS No.156 is not expected to have a material effect on our consolidated financialposition, results of operations or cash flows.

In June 2006, the FASB issued FIN 48, *Accounting for Uncertainty in Income Taxes, an Interpretation of FASBStatement No. 109*, which clarifies the accounting foruncertainty in income taxes recognized in accordance withSFAS No. 109, *Accounting for IncomeTaxes*. FIN 48 prescribes a benefit recognition model with atwo-step approach, a more-likely-than-not recognition criterion and ameasurement attribute that measures the position as the largest amount of taxbenefit that is greater than 50% likely of being realized upon settlement. Ifit is not more likely than not that the benefit will be sustained on itstechnical merits, no benefit will be recorded. FIN 48 also requires thatthe amount of interest expense to be recognized related to uncertain taxpositions be computed by applying the applicable statutory rate of interest tothe difference between the tax position recognized in accordance withFIN 48 and the amount previously taken or expected to be taken in a taxreturn. The change in net assets as a result of applying this pronouncementwill be considered a change in accounting principle with the cumulative effectof the change treated as an offsetting adjustment to the opening balance ofretained earnings or goodwill, if allowed under existing accounting standards,in the period of transition. FIN 48 is effective as of January 1,2007 and the Company is currently evaluating the effects, if any, that FIN 48will have on its financial statements.

In September 2006, the FASB issued SFAS No. 157, *Fair Value Measurements,* which provides guidance for usingfair value to measure assets and liabilities. The standard also gives expanded information about the extent to whichcompanies measure assets and liabilities at fair value, the information used tomeasure fair value, and the effect of fair value measurements on earnings. SFASNo. 157 does not expand the use of fair value in any new circumstances.  SFAS No. 157 establishes a fair valuehierarchy that prioritizes the information used to develop fair valueassumptions.  SFAS No. 157 is effectivefor financial statements issued for fiscal years beginning after November 15,2007.  Early adoption is encouraged.  The Company is currently assessing theimpact, if any, that SFAS No. 157 will have on its financial statements.

In February 2007, the FASB issued SFAS No. 159, *The Fair Value Option for Financial Assets and Financial Liabilities*,which permits entities to choose to measure many financial instruments andcertain other items at fair value.  Theobjective is to improve financial reporting by providing entities with theopportunity to mitigate volatility in reported earnings caused by measuringrelated assets and liabilities differently without having to apply complexhedge accounting provisions.  SFAS No.159 applies to all entities and is effective for fiscal years beginning afterNovember 15, 2007.  The Company iscurrently determining the impact, if any, that SFAS No. 159 will have on itsfinancial statements.

F-13

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***Reclassifications***-Certain reclassifications of prior period balances have been made to conform tocurrent reporting practices.

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

Below are the components ofAccounts Receivable, Joint Interest Owners and Other, as of December 31, 2006and 2005:
|                                                                      | ** ** | **December 31,**   | ** ** |
|----------------------------------------------------------------------|------------|-------------------------|------------|
| ** **                                                           | ** ** | **2006**                | ** ** | **2005** | ** ** |
| ** **                                                           | ** ** | **(in thousands)** | ** ** |
| Joint interest  owners                                               |       | $                       | 2,218      |   | $ | 1,212 |   |
| Chapman Ranch  Field Asset Acquisition Purchase Price Adjustment (1) |       | —                  |       | 818 |   |
| Other  Receivables (2)                                               |       | 2                       |       | 75 |   |
| Allowance for  Doubtful Accounts Receivable (joint interest owners)  |       | (3                      | )          | (5 | ) |
| Net Accounts  Receivable, joint interest owners and other            |       | $                       | 2,217      |   | $ | 2,100 |   |

 

----

(1)     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 in 2005 (see Note 6).

(2)     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 receivable, trade and joint interest owners and other, for the yearsended December 31, 2006, 2005 and 2004:
| ** **                         | ** ** | **Balance at  Beginning of  Year** | ** ** | **Charged to  Costs and  Expenses** | ** ** | **Deductions  and Other** | ** ** | **Balance at  End of  Year** | ** ** |
|------------------------------------|------------|----------------------------------------------|------------|-----------------------------------------------|------------|--------------------------------|------------|----------------------------------------|------------|
| ** **                         | ** ** | **(in thousands)**                      | ** ** |
| **Year  ended December 31, 2006:** | ** ** | ** **                                   | ** ** | ** **                                    | ** ** | ** **                     | ** ** | ** **                             | ** ** |
| Allowance for doubtful accounts    |       | $                                            | 530        |                                          | $          | —                         |       | $                                      | (2         | ) | $ | 528 |   |
| **Year  ended December 31, 2005:** | ** ** | ** **                                   | ** ** | ** **                                    | ** ** | ** **                     | ** ** | ** **                             | ** ** |
| Allowance for doubtful accounts    |       | $                                            | 607        |                                          | $          | 65                             |       | $                                      | (142       | ) | $ | 530 |   |
| **Year  ended December 31, 2004:** | ** ** | ** **                                   | ** ** | ** **                                    | ** ** | ** **                     | ** ** | ** **                             | ** ** |
| Allowance for  doubtful accounts   |       | $                                            | 607        |                                          | $          | —                         |       | $                                      | —     |   | $ | 607 |   |

 

**4.     OTHER CURRENT ASSETS**

Below are the components of other current assets as of December 31, 2006and 2005:
|                                      | ** ** | **December 31,**   | ** ** |
|--------------------------------------|------------|-------------------------|------------|
| ** **                           | ** ** | **2006**                | ** ** | **2005** | ** ** |
| ** **                           | ** ** | **(in thousands)** | ** ** |
| Prepaid  insurance                   |       | $                       | 397        |   | $ | 388 |   |
| Prepayments and  deposits to vendors |       | 387                     |       | 323 |   |
| Prepaid seismic  licenses            |       | 266                     |       | — |   |
| Drilling  advances                   |       | 1,151                   |       | 4,286 |   |
| Inventory (1)                        |       | 1,758                   |       | 1,440 |   |
| Total other  current assets          |       | $                       | 3,959      |   | $ | 6,437 |   |

 

----

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

F-14

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**5.     PROPERTY AND EQUIPMENT**

At December 31, 2006 and 2005, property and equipmentconsisted of the following:
|                                                       | ** ** | **December 31,**   | ** ** |
|-------------------------------------------------------|------------|-------------------------|------------|
| ** **                                            | ** ** | **2006**                | ** ** | **2005** | ** ** |
| ** **                                            | ** ** | **(in thousands)** | ** ** |
| Developed oil  and natural gas properties             |       | $                       | 521,713    |   | $ | 401,697 |   |
| Unevaluated oil  and natural gas properties           |       | 57,577                  |       | 36,949 |   |
| Computer  equipment and software                      |       | 4,602                   |       | 4,491 |   |
| Other office  property and equipment                  |       | 2,588                   |       | 2,515 |   |
| Total property and equipment                          |       | 586,480                 |       | 445,652 |   |
| Accumulated  depletion, depreciation and amortization |       | (297,023                | )          | (139,196 | ) |
| Total property  and equipment, net                    |       | $                       | 289,457    |   | $ | 306,456 |   |

 

The following table summarizes the cost of theproperties not subject to amortization by the year the cost was incurred:
|                      | ** ** | **December 31,**   | ** ** |
|----------------------|------------|-------------------------|------------|
| ** **           | ** ** | **2006**                | ** ** | **2005** | ** ** |
| ** **           | ** ** | **(in thousands)** | ** ** |
| Year cost  incurred: |       |                    |       |   |   |
| 1999                 |       | $                       | 193        |   | $ | 193 |   |
| 2000                 |       | —                  |       | — |   |
| 2001                 |       | 22                      |       | 22 |   |
| 2002                 |       | 88                      |       | 88 |   |
| 2003                 |       | 118                     |       | 248 |   |
| 2004                 |       | 228                     |       | 3,510 |   |
| 2005                 |       | 26,150                  |       | 32,888 |   |
| 2006                 |       | 30,778                  |       | — |   |
| Total                |       | $                       | 57,577     |   | $ | 36,949 |   |

 

**6.     ACQUISITIONS AND DIVESTITURES**

**Chapman Ranch Field Acquisitionin 2006 -**On December 12, 2006, the Company executed anagreement to acquire certain working interests in the Chapman Ranch Field inNueces County, Texas from Kerr-McGee Oil & Gas Onshore LP (“Kerr-McGee”), awholly owned subsidiary of Anadarko Petroleum Corporation.  In late 2005, the Company acquirednon-operated working interests in certain wells in this field, as discussedbelow.  Upon the closing of theKerr-McGee acquisition on December 28, 2006, the Company assumed operatorshipof Chapman Ranch.  The base purchaseprice of the acquisition was $26.0 million. The purchase price was preliminarily adjusted at closing to $25.0million (including a previously paid deposit of $2.6 million) as a result ofadjustments to the purchase price for the results of operations between theDecember 1, 2006 effective date and the December 28, 2006 closing date, andother purchase price adjustments.  Theremay be post-closing adjustments to the purchase price for results of operationsbetween the effective date and closing date as further information becomesavailable.  The Company financed thepurchase price of the Kerr-McGee acquisition through $24.0 million inborrowings under its Credit Facility, the borrowing base of which was increasedas a result of this transaction.

**Chapman Ranch Field Acquisitionsin 2005 -**On September 21, 2005, the Company executed twoseparate and definitive agreements for the acquisition of (i) the stock of aprivate company, Cinco Energy Corporation (“Cinco”), whose primary asset is ownershipof working interests in oil and natural gas properties located on the ChapmanRanch Field in Nueces County, Texas and (ii) additional working interests inthe Chapman Ranch Field owned by two other private companies for an aggregatefinal purchase price of approximately $74.9 million (of which $46.9 million wasattributable to the stock purchase and $28.0 million was attributable to theworking interest asset purchase). The Company allocated approximately $17.5million of the total purchase price to the unproved property category. Bothpurchase prices were subject to adjustment pursuant to the provisions of theapplicable agreements. The Company also agreed to pay the sellers an aggregateincremental purchase price of $5.2 million (of which $3.0 million wasattributable to the stock purchase and $2.2 million was attributable to theworking interest

F-15

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asset purchase) related to the operator obtaininghigh-cost gas certification on or before January 31, 2006, which would providefor severance tax abatements on the properties acquired. The operator of theproperties filed for the abatements and the Company was notified that not allof the properties qualified for high-cost gas certification, therefore theincremental purchase price was reduced to $4.8 million in January 2006. OnNovember 30, 2005, the Company paid a portion of the incremental purchase priceof $3.9 million when a portion of the properties qualified for thecertification and incurred a contingent liability for the remaining balance of$0.9 million, which was paid to the Sellers in the first quarter of 2006. TheCompany financed the acquisitions through borrowings under its credit facility,the borrowing base of which increased in connection with these transactions andother recent activities since the last redetermination.

The asset purchase closedon October 13, 2005. The final purchase price of $28.0 million was adjusted forthe incremental purchase price (see above) and the results of operationsbetween the September 1, 2005 effective date and the October 13, 2005 closingdate, pursuant to the closing adjustment provisions of the relevant agreement.

The stock purchase closedNovember 30, 2005. The final purchase price of $46.9 million was subject toadjustment for, among other things, working capital as of September 1, 2005 andan incremental purchase price (see above), pursuant to the closing provisionsof the relevant agreement.

Pursuant to the terms ofthe stock purchase agreement, Cinco changed its name to Edge PetroleumProduction Company.  It will remain awholly owned subsidiary of the Company going forward.

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 allocation of the final purchase price to specific assets and liabilities has been adjusted for actual amounts.
| ***In thousands:***          | *** *** | *** *** | *** *** |
|------------------------------|--------------|--------------|--------------|
| Cash                         |         | $            | 8,305        |   |
| Current assets               |         | 2,470        |         |
| Properties and  equipment    |         | 53,065       |         |
| Deferred tax  liability (1)  |         | (14,945      | )            |
| Current  liabilities         |         | (1,919       | )            |
| Asset retirement  obligation |         | (64          | )            |
| Stockholders’ equity    |         | $            | 46,912       |   |

 

----

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

The following unaudited proforma results for 2005 show the effect on the Company’s consolidated results ofoperations as if the Cinco transaction had occurred on January 1, 2005.  The following 2005 unaudited pro formaresults are the result of combining the statement of operations of Edge withthe statement of income for Cinco, adjusted for (i) assumption of AROliabilities and accretion expense for the properties acquired, (ii) depletion,depreciation and amortization expense applied to the adjusted basis of theproperties acquired using the purchase method of accounting, (iii) conversionof Cinco from successful efforts method of accounting to the full cost methodof accounting,  and (iv) the relatedincome tax effects of these adjustments based on the applicable statutoryrates.  The pro forma information isbased upon numerous assumptions, and is not necessarily indicative of futureresults of operations.
|                               | ** ** | **For the Year Ended December 31,  2005** | ** ** |
|-------------------------------|------------|--------------------------------------------------------------------|------------|
| ** **                    | ** ** | **(unaudited)**                                                    | ** ** |
| ** **                    | ** ** | **(in thousands, except  share data)**              | ** ** |
| Revenue                       |       | $                                                                  | 131,289    |   |
| Net income                    |       | $                                                                  | 27,202     |   |
| Net income per  common share: |       |                                                               |       |
| Basic                         |       | $                                                                  | 1.59       |   |
| Diluted                       |       | $                                                                  | 1.53       |   |

 

F-16

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**Contango Asset Acquisition -**OnDecember 29, 2004, the Company consummated the acquisition of interests in oiland natural gas properties located in south Texas from Contango Oil & GasCompany (“Contango”). The final purchase price for the acquisition was $40.1million, which was adjusted for the results of operations between the July 1,2004 effective date and the December 29, 2004 closing date, pursuant to theclosing adjustment provisions. The purchase price was funded from the netproceeds of a public offering of common stock completed on December 21, 2004(see Note 11).

**Divestitures -**In 2006, the Companyconsummated the divestiture of its Buckeye properties located in Live OakCounty, Texas for net proceeds of $627,645. During 2005, the Company had no divestitures of oil and gas properties.  During 2004, the Company sold oil and gasproperties for net proceeds of $60,000. The Company’s 2004 asset divestitures related primarily to the sale ofcertain oil and gas properties and equipment in Texas, Mississippi andLouisiana.  Proceeds from thesedispositions were credited to the full-cost pool.

**7.     ASSET RETIREMENT OBLIGATIONS**

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

The Companyadopted SFAS No. 143 on January 1, 2003, whereby the Company records anabandonment liability associated with its oil and natural gas wells when thoseassets are placed in service.  Thechanges to the ARO during the periods ended December 31, 2006 and 2005 are asfollows:
|                                  | ** ** | **For the Year Ended December 31,** | ** ** |
|----------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                       | ** ** | **2006**                                                     | ** ** | **2005** | ** ** |
| ** **                       | ** ** | **(in thousands)**                                      | ** ** |
| ARO, beginning  of year          |       | $                                                            | 2,767      |   | $ | 2,189 |   |
| Additional  liabilities incurred |       | 572                                                          |       | 588 |   |
| Liabilities  settled             |       | (199                                                         | )          | (151 | ) |
| Accretion  expense               |       | 189                                                          |       | 141 |   |
| Revisions                        |       | 42                                                           |       | — |   |
| ARO, end of year                 |       | $                                                            | 3,371      |   | $ | 2,767 |   |
|                             |       |                                                         |       |   |   |
| Current portion                  |       | $                                                            | 213        |   | $ | 203 |   |
| Long-term portion                |       | $                                                            | 3,158      |   | $ | 2,564 |   |

 

AROliabilities incurred during the year ended December 31, 2006 includeobligations assumed for 39 wells that were successfully drilled during theyear, several non-operated wells that were not previously identified andadjustments for additional working interests acquired in 19 wells in theChapman Ranch Field. Liabilities settled during the year ended December 31,2006 included 30 wells that were either plugged or sold.

**8.     ACCRUED LIABILITIES**

Below are the components of accrued liabilities as of December 31, 2006and 2005:

F-17

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|                                                              | ** ** | **As of December 31,** | ** ** |
|--------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                   | ** ** | **2006**                              | ** ** | **2005** | ** ** |
| ** **                                                   | ** ** | **(in thousands)**               | ** ** |
| Accrued capital  expenditures                                |       | $                                     | 6,603      |   | $ | 9,428 |   |
| Professional  services                                       |       | 1,244                                 |       | 850 |   |
| Salaries and  benefits                                       |       | 931                                   |       | 1,600 |   |
| Royalties  payable                                           |       | 4,014                                 |       | 4,133 |   |
| Lease operating  expenses including ad valorem taxes payable |       | 2,438                                 |       | 1,409 |   |
| Litigation  settlement                                       |       | 1,328                                 |       | — |   |
| Other                                                        |       | 80                                    |       | 474 |   |
| Total accrued  liabilities                                   |       | $                                     | 16,638     |   | $ | 17,894 |   |

 

**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 revenue, as well as to reduce exposure from pricefluctuations.  While the use of thesearrangements may limit the Company’s ability to benefit from increases in theprice of oil and natural gas, it also reduces the Company’s potential exposureto adverse price movements.  The Company’sarrangements, to the extent it enters into any, apply to only a portion of itsproduction and provide only partial price protection against declines in oiland natural gas prices. None of these instruments are used for trading orspeculative purposes. On a quarterly basis, the Company’s management sets allof the Company’s price-risk management policies, including volumes, types ofinstruments and counterparties. These policies are implemented by managementthrough the execution of trades by the Chief Financial Officer afterconsultation and concurrence by the President and Chairman of the Board.  The Board of Directors monitors the Company’spolicies and trades.

Allof these price-risk management transactions are considered derivativeinstruments and accounted for in accordance with SFAS No. 133, *Accounting for Derivative Instruments and HedgingActivities* (as amended).These derivative instruments are intended to hedge our price risk and may beconsidered hedges for economic purposes, but certain of these transactions maynot qualify for cash flow hedge accounting. All derivative instrument contractsare recorded on the balance sheet at fair value and the cash flows resultingfrom settlement of these derivative transactions are classified in operatingactivities on the statement of cash flows. For those derivatives in whichmark-to-market accounting treatment is applied, the changes in fair value arenot deferred through other comprehensive income on the balance sheet.  Rather they are immediately recorded in totalrevenue on the statement of operations. For those derivative instrument contracts that are designed and qualifyfor cash flow hedge accounting, the effective portion of the changes in thefair value of the contracts is recorded in other comprehensive income on thebalance sheet and the ineffective portion of the changes in the fair value ofthe contracts is recorded in total revenue on the statement of operations, ineither case, as such changes occur. When the hedged production is sold, therealized gains and losses on the contracts are removed from other comprehensiveincome and recorded in revenue. While the contract is outstanding, theineffective gain or loss may increase or decrease until settlement of thecontract depending on the fair value at the measurement dates.

Duringthe first quarter of 2006, the Company determined that the cash flow hedgeaccounting treatment previously applied to its natural gas contracts should bediscontinued due to projected changes in the 2006 physical production volumeshedged and to give the Company more flexibility in how it markets its physicalproduction. In 2006, the Company has applied mark-to-market accountingtreatment to all outstanding derivative contracts, therefore the changes infair value are not deferred through other comprehensive income, but ratherrecorded in revenue immediately as unrealized gains or losses. Going forward,the Company will continue to evaluate the terms of new contracts entered intoto determine whether cash flow hedge accounting treatment or mark-to-marketaccounting treatment will be applied. In the past, the Company has usedmark-to-market accounting treatment for its crude oil contracts and cash flowhedge accounting treatment for its natural gas contracts.  Therefore, unrealized gains and losses on thechange in fair value of natural gas contracts between periods may not becomparable.

F-18

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For the years ended December 31, 2006, 2005 and 2004,the Company included in revenue realized and unrealized losses related to its derivativecontracts. There was no ineffectiveness recognized during the years endedDecember 31, 2005 and 2004 when cash flow hedge accounting was applied to theCompany’s natural gas contracts. For the three years ended December 31, 2006,2005 and 2004, the Company included in total revenue the following realized andunrealized gains and losses:
| ** **                                          | ** ** | **For the Year Ended December 31,** | ** ** |
|-----------------------------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                                          | ** ** | **2006**                                                     | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                          | ** ** | **(in thousands)**                                      | ** ** |
| Natural gas collar  realized settlements            |       | $                                                            | 4,699      |   | $ | (1,230 | ) | $ | (328 | ) |
| Crude oil collar  realized settlements              |       | —                                                       |       | (1,757 | ) | (881 | ) |
| Hedge premium  reclassification                     |       | —                                                       |       | — |   | (686 | ) |
| Natural gas collar  unrealized change in fair value |       | 4,686                                                        |       | — |   | — |   |
| Crude oil collar  unrealized change in fair value   |       | 345                                                          |       | 720 |   | (565 | ) |
| Gain (loss) on hedging  and derivatives             |       | $                                                            | 9,730      |   | $ | (2,267 | ) | $ | (2,460 | ) |

 

Thefair value of outstanding hedge and derivative contracts at December 31, 2006and 2005 reflected on the balance sheet were as follows: 
| ** **                | ** **   | ** **                | ** **   | ** **    | ** **   | ** **   | ** **   | ** **        | ** **   | ** **       | ** **   | **Fair Value of Outstanding Hedging and  Derivative Contracts as of** | ** **   |
|---------------------------|--------------|---------------------------|--------------|---------------|--------------|--------------|--------------|-------------------|--------------|------------------|--------------|---------------------------------------------------------------------------------------------------------------|--------------|
| ** **                | ** **   | ** **                | ** **   | ** **    | ** **   | ** **   | ** **   | **Price**         | ** **   | **Volumes**      | ** **   | **December 31,**                                                                                         | ** **   |
| **Transaction Date** | ** **   | **Transaction Type** | ** **   | **Beginning** | ** **   | **Ending**   | ** **   | **Per Unit** | ** **   | **Per Day** | ** **   | **2006**                                                                                                      | ** **   | **2005** | ** ** |
| ** **                | ** **   | ** **                | ** **   | ** **    | ** **   | ** **   | ** **   | ** **        | ** **   | ** **       | ** **   | **(in thousands)**                                                                                       | ** **   |
| ***Natural  Gas (1):***   |         |                      |         |          |         |         |         |              |         |             |         |                                                                                                          |         |   |   |
| *** ***              |         |                      |         |          |         |         |         |              |         |             |         |                                                                                                          |         |   |   |
| 08/05                     |         | Natural Gas Collar        |         | 01/01/2006    |         | 12/31/2006   |         | $7.00-$10.50      |         | 10,000MMbtu      |         | $                                                                                                             | —       |   | $ | (2,498 | ) |
|                      |         |                      |         |          |         |         |         |              |         |             |         |                                                                                                          |         |   |   |
| 08/05                     |         | Natural Gas Collar        |         | 01/01/2006    |         | 12/31/2006   |         | $7.00-$16.10      |         | 10,000MMbtu      |         | —                                                                                                        |         | (137 | ) |
|                      |         |                      |         |          |         |         |         |              |         |             |         |                                                                                                          |         |   |   |
| 08/06                     |         | Natural Gas Collar        | (3)          | 01/01/2007    |         | 12/31/2007   |         | $7.50-$11.50      |         | 5,000 MMbtu      |         | 2,301                                                                                                         |         | — |   |
|                      |         |                      |         |          |         |         |         |              |         |             |         |                                                                                                          |         |   |   |
| 08/06                     |         | Natural Gas Collar        | (3)          | 01/01/2007    |         | 12/31/2007   |         | $7.50-$12.00      |         | 5,000 MMbtu      |         | 2,385                                                                                                         |         | — |   |
|                      |         |                      |         |          |         |         |         |              |         |             |         |                                                                                                          |         |   |   |
| ***Crude  Oil (2):***     | *** *** | *** ***              | *** *** | *** ***  | *** *** | *** *** | *** *** | *** ***      | *** *** | *** ***     | *** *** | *** ***                                                                                                  | *** *** | *** *** | *** *** |
| *** ***              | *** *** | *** ***              | *** *** | *** ***  | *** *** | *** *** | *** *** | *** ***      | *** *** | *** ***     | *** *** | *** ***                                                                                                  | *** *** | *** *** | *** *** |
| 08/05                     |         | Crude Oil Collar          |         | 01/01/2006    |         | 12/31/2006   |         | $55.00-$80.00     |         | 400Bbl           |         | —                                                                                                        |         | 156 |   |
|                      |         |                      |         |          |         |         |         |              |         |             |         |                                                                                                          |         |   |   |
| 08/06                     |         | Crude Oil Collar          |         | 01/01/2007    |         | 12/31/2007   |         | $70.00-$87.50     |         | 400 Bbl          |         | 1,047                                                                                                         |         | — |   |
|                      |         |                      |         |          |         |         |         |              |         |             |         |                                                                                                          |         |   |   |
| 12/06                     |         | Crude Oil Swap            |         | 01/01/2007    |         | 12/31/2007   |         | $66.00            |         | 600 Bbl          |         | 212                                                                                                           |         | — |   |
|                      |         |                      |         |          |         |         |         |              |         |             |         |                                                                                                          |         |   |   |
| 12/06                     |         | Crude Oil Swap            |         | 01/01/2008    |         | 12/31/2008   |         | $66.00            |         | 1,500 Bbl        |         | (758                                                                                                          | )            | — |   |
|                      |         |                      |         |          |         |         |         |              |         |             |         | $                                                                                                             | 5,187        |   | $ | (2,479 | ) |

 

----

(1)          The Company’s current natural gas collars were entered into on a perMMbtu delivered price basis, using the Houston Ship Channel Index.  Cash flow hedge accounting, which was appliedto these contracts in 2005, was discontinued in 2006. During 2006,mark-to-market accounting treatment was applied to these contracts and thechange in fair value is reflected in total revenue during the year.

(2)          Cash flow hedge accounting is not applied to the Company’s crude oilcontracts, which were entered into on a per barrel delivered price basis, usingthe West Texas Intermediate Light Sweet Crude Oil Index, with settlement foreach calendar month occurring five business days following the expiration date.Mark-to-market accounting treatment is applied to these contracts and thechange in fair value is reflected in total revenue during the year.

(3)          Subsequent to December 31, 2006, two natural gas collars covering aportion of our 2007 estimated production were terminated and replaced with newcollars.  The terms of the new contractsare detailed in the table below.

Derivative contracts entered into after December 31,2006 were as follows: 
| ** **            | ** ** | ** **                         | ** ** | **Effective Dates** | ** ** | ** ** | ** ** | ** **                   | ** ** |
|-----------------------|------------|------------------------------------|------------|--------------------------|------------|------------|------------|------------------------------|------------|
| **Transaction  Date** | ** ** | **Transaction Type (1)** | ** ** | **Beginning**            | ** ** | **Ending** | ** ** | **Price Per Unit** | ** ** | **Volume Per  Day** | ** ** |
|                  |       |                               |       |                     |       |       |       |                         |       |   |   |
| 01/07                 |       | Natural Gas Collar                 |       | 01/01/08                 |       | 12/31/08   |       | $7.50-$9.00                  |       | 10,000 MMbtu |   |
|                  |       |                               |       |                     |       |       |       |                         |       |   |   |
| 01/07                 |       | Natural Gas Collar                 |       | 01/01/08                 |       | 12/31/08   |       | $7.50-$9.02                  |       | 10,000 MMbtu |   |
|                  |       |                               |       |                     |       |       |       |                         |       |   |   |
| 01/07                 |       | Natural Gas Collar                 | (2)        | 02/01/07                 |       | 12/31/07   |       | $7.02-$9.00                  |       | 15,000 MMbtu |   |
|                  |       |                               |       |                     |       |       |       |                         |       |   |   |
| 01/07                 |       | Natural Gas Collar                 | (2)        | 02/01/07                 |       | 12/31/07   |       | $7.00-$9.00                  |       | 15,000 MMbtu |   |
|                  |       |                               |       |                     |       |       |       |                         |       |   |   |
| 01/07                 |       | Natural Gas Collar                 |       | 02/01/07                 |       | 12/31/07   |       | $7.00-$9.00                  |       | 10,000 MMbtu |   |
|                  |       |                               |       |                     |       |       |       |                         |       |   |   |
| 01/07                 |       | Natural Gas Collar                 |       | 01/01/08                 |       | 12/31/08   |       | $7.50-$9.00                  |       | 20,000 MMbtu |   |

 

F-19

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(1)   The Company’s January 2007 natural gas collars were entered into on aper MMbtu delivered price basis, using the NYMEX Natural Gas Index, withsettlement for each calendar month occurring five business days following theexpiration date. Mark-to-market accounting treatment will be applied to thesecontracts and the change in fair value will be reflected in total revenue.

(2)   These natural gas collars replaced contracts that were cancelledsubsequent to December 31, 2006.

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

OnDecember 21, 2006, the Company amended its Third Amended and Restated CreditAgreement (the “Prior Credit Facility”), which it had originally entered intoin March 2004 (effective December 31, 2003) and previously amended on December4, 2006.  The Prior Credit Facilitypermitted borrowings up to the lesser of (i) the borrowing base and (ii) $150.0million.  Effective December 21, 2006,the Prior Credit Facility’s borrowing base was increased from $125.0 million to$140.0 million. The borrowing base under the Prior Credit Facility was increasedas a result of the Kerr-McGee acquisition and the Company’s drilling activitiessince the last redetermination. The Company’s available borrowing capacityunder this facility was $11.0 million at December 31, 2006.

ThePrior Credit Facility was scheduled to mature on March 31, 2008 and was securedby substantially all of the Company’s assets. Borrowings under the Prior CreditFacility bore interest at rates that were variable based on percentage usage ofthe facility.  Borrowings could be atPrime plus a margin of 0% to 0.25% or at LIBOR plus a margin of 1.75% to2.125%.  Outstanding availability boreinterest rates of 0.25% to 0.50% based on utilization levels.  At December 31, 2006 the interest ratesapplied to the Company’s outstanding Prime and LIBOR borrowings were 8.500% and7.485%, respectively. As of December 31, 2006, $129.0 million in borrowingswere outstanding under the Prior Credit Facility.

ThePrior Credit Facility provided for certain restrictions, including but notlimited to, limitations on additional borrowings, sales of oil and natural gasproperties or other collateral, and engaging in merger or consolidationtransactions. The Prior Credit Facility also prohibited dividends on our commonstock and certain distributions of cash or properties and certain liens.  The Prior Credit Facility also contained thefollowing financial covenants, among others:

·      The EBITDAX to InterestExpense ratio required that the ratio of (a) consolidated EBITDAX (defined asEBITDA plus similar non-cash items and exploration and abandonment expenses forsuch period) 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 ratiorequired that the amount of the Company’s consolidated current assets less itsconsolidated current liabilities, as defined in the Credit Facility Agreement,be at least $1.0 million. For the purposes of calculating the Working Capitalratio, the total of current assets was adjusted for unused capacity under theCredit Facility Agreement, and derivative financial instruments and the totalof current liabilities is adjusted for derivative financial instruments andasset retirement obligations.

·      TheMaximum Leverage ratio required that the ratio, as of the last day of anyfiscal quarter, of (a) Total Indebtedness (as defined in the Credit FacilityAgreement) as of such fiscal quarter to (b) an amount equal to consolidatedEBITDAX for the two quarters then ended times two, not be greater than 3.0 to1.0.

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

F-20

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

During the secondquarter 2005, the Company filed a registration statement with the SEC whichregistered offerings up to $390 million of any combination of debt securities,preferred stock, common stock or warrants for debt securities or equitysecurities of the Company. Net proceeds, terms and pricing of the offering ofsecurities issued under the shelf registration statement will be determined atthe time of the offerings. The shelf registration statement does not provideassurance that the Company will or could sell any such securities. The Company’sability to utilize the shelf registration statement for the purpose of issuing,from time to time, any combination of debt securities, preferred stock, commonstock or warrants will depend upon, among other things, market conditions andthe existence of investors who wish to purchase the Company’s securities atprices acceptable to the Company.

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 othergeneral corporate purposes. On January 5, 2005, the underwriters exercisedtheir over-allotment option for an additional 0.5 million shares of commonstock, which generated additional net proceeds of $7.2 million. These fundswere used to reduce outstanding debt. Each of these sales was made under theCompany’s initial shelf registration statement. At December 31, 2006, theCompany had $390 million available for issuance under its 2005 shelfregistration statement.

InJanuary 2007, the Company completed an offering of 10.925 million shares of itscommon stock and 2.875 million shares of 5.75% Series A cumulative convertibleperpetual preferred stock, as discussed further below in Note 12.  As a result of the offerings, the Company hadapproximately $101.5 million remaining available under its 2005 shelfregistration statement.

**12.****       SUBSEQUENT EVENTS**

**Acquisitions** -On November 16, 2006, the Company entered into two separate purchase and saleagreements (one of which was subsequently amended) with Smith Production Inc. (“Smith”)for (A) (i) ownership interests in certain oil and gas properties located in 13counties in southeast and south Texas, consisting of approximately 150 gross(74 net) producing wells from Smith and eight other owners who transferredtheir interests to Smith prior to the closing, (ii) an ownership interest inapproximately 17,000 gross (12,250 net) developed acres and 56,000 gross(16,000 net) undeveloped acres of leasehold, (iii) 25% of Smith’s option andleasehold rights and exploration and development rights in an approximate 95square mile exploration project area known as the Mission project area, also insouth Texas, and (iv) certain gathering facilities and ownership toapproximately 13 miles of natural gas gathering pipelines and relatedinfrastructure serving producing assets in southeast Texas ((i) through (iv)collectively referred to as the “Smith Properties”); and (B) working interest,option and leasehold rights in two exploration ventures in separate areas,primarily in Texas, from Smith (the “Smith Ventures” and collectively with theSmith Properties, the “Properties”).  Thecombined cash purchase price paid at closing on January 31, 2007 wasapproximately $379.8 million for the Smith Properties and $10.0 million for theSmith Ventures.  The purchase price forthe Smith Properties was adjusted from the base purchase price of $385 millionfor, among other things, the results of operations of the Smith Propertiesbetween the January 1, 2007 effective date and the January 31, 2007 closingdate.  The Company expects furtheradjustments to the purchase price pursuant to the post-closing adjustmentprovisions of the amended purchase and sale agreements.

**Public Offerings**- In order to finance a portion of the Smith acquisition, on January 30, 2007,the Company completed an offering of 10.925 million shares of its common stock,as well as an offering of 2.875 million shares of 5.75% Series A cumulativeconvertible perpetual preferred stock. The shares were offered to the public at a price of $13.25 per share ofcommon stock and $50.00 per share of preferred stock.  The Company received net proceeds ofapproximately $276.7 million, before other direct costs, from the offerings($138.1 million from the common offering and $138.6 from the preferred offering),after deducting underwriting discounts and commissions and the estimatedexpenses of the offerings. As a result of the offerings, the Company hadapproximately $101.5 million remaining available under its 2005 shelfregistration statement as of March 9, 2007.

**Credit Facility** - On January 30, 2007, the Companyentered into a Fourth Amended and Restated Credit Agreement for a new RevolvingCredit Facility with Union Bank of California (“UBOC”) and the other lendersparty thereto. Pursuant to the agreement, UBOC will act as the administrative agentfor a senior, first lien secured

F-21

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borrowing baserevolving credit facility (the “Credit Facility”) for the Company in an amountequal to $750 million, of which $320 million was initially made available underthe borrowing base established at the closing. The Credit Facility has a letterof credit sub-limit of $20 million. In connection with the Credit Facility, theCompany paid the lenders fees in an amount equal to 1.00% of the initialborrowing base established under the Credit Facility, or $3.2 million, onJanuary 31, 2007.  The Company paid approximately $0.4 million to thelenders for certain other administrative fees, fronting fees and work fees inconnection with the Credit Facility.

TheCredit Facility matures on January 31, 2011 and is secured by substantially allof the Company’s assets.  Borrowingsunder the Credit Facility bear interest at LIBOR plus an applicable marginranging from 1.25% to 2.5%, with an unused commitment fee ranging from 0.50% to0.25%.

TheCredit Facility provides for certain restrictions and covenants, including, butnot limited to, limitations on additional borrowings, sales of oil and naturalgas properties or other collateral, and engaging in merger or consolidationtransactions. The Credit Facility restricts dividends and certain distributionsof cash or properties and certain liens and also contains financial covenantsincluding, without limitation, the following:

·                  AnEBITDAX to interest expense ratio requires that as of the last day of eachfiscal quarter the ratio of (a) the Company’s consolidated EBITDAX (defined asEBITDA plus similar non-cash items and exploration and abandonment expenses forsuch period) to (b) the Company’s consolidated interest expense, not be lessthan 2.5 to 1.0, calculated on a cumulative quarterly basis for the first 12months after the closing of the Credit Facility and then on a rolling fourquarter basis.

·                  Acurrent ratio requires that as of the last day of each fiscal quarter the ratioof the Company’s consolidated current assets to the Company’s consolidatedcurrent liabilities, as defined in the Credit Facility, be at least 1.0 to 1.0.

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

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

UBOChad previously provided the Company a commitment letter for a $250 millionsenior, second lien secured bridge loan facility (the “Bridge Loan Facility”).The Bridge Loan Facility, along with the Credit Facility, was intended toreplace the Company’s existing credit facility and to fund the Smithacquisition described above if the Company was unable to complete one or bothof its previously announced public offerings. Due to the successful completionof the Company’s public offerings of common stock and Series A preferred stockon January 30, 2007, the Company did not enter into the Bridge Loan Facility.The Company paid an amount equal to 0.50% of the commitment under the BridgeLoan Facility, or $1.3 million, on January 31, 2007 which was recorded in thefirst quarter of 2007.

In connection with the Credit Facility, Edgeterminated its existing Third Amended and Restated Credit Agreement, which it had originally entered intoin March 2004 (effective December 31, 2003). The balance of the borrowings under this prior credit facility of$129.0 million was repaid on January 30, 2007 with the proceeds from the publicofferings described above.  As of March9, 2007, the Company had borrowings of $235.0 million outstanding under itsCredit Facility.

**13.****       COMMITMENTS ANDCONTINGENCIES**

***Commitments -***AtDecember 31, 2006, the Company was obligated under non-cancelable operatingleases.  Following is a schedule of theremaining future minimum lease payments under these leases:

F-22

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|           | ** ** | **(in thousands)** | ** ** |
|-----------|------------|-------------------------|------------|
| 2007      |       | $                       | 817        |   |
| 2008      |       | 826                     |       |
| 2009      |       | 818                     |       |
| 2010      |       | 816                     |       |
| 2011      |       | 804                     |       |
| Remainder |       | 1,273                   |       |
| Total     |       | $                       | 5,354      |   |

 

Rentexpense for the years ended December 31, 2006, 2005 and 2004 was approximately$0.7 million, $0.7 million, and $0.5 million, respectively.

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

**Texas Comptroller Audit** - During thesecond quarter of 2004, the Company received notice that a subsidiary’sfranchise tax returns for the State of Texas would be audited for the tax years1999 through 2002. After reviewing the documents submitted, the agentrepresenting the Office of the Comptroller of the State of Texas proposedadjustments to the calculation that would result in an increased franchise taxliability.  The agent maintained that transfers by the Company to itssubsidiary, which had been classified as intercompany loans, should instead beclassified as equity investments in the subsidiary. The State of Texasoriginally proposed that the franchise tax liability of the subsidiaries wouldbe increased by approximately $3.0 million for the four-year period underaudit.

Duringthe third quarter of 2006, the Company and the Comptroller agreed upon a methodof computing the Company’s franchise tax liability to the State of Texas fortax years 1999 through 2002 that resulted in a total one-time payment of$144,474, plus penalties of $9,228, which was recorded in 2006.  Interest on this settlement of $40,150 waspaid in the fourth quarter of 2006.

**Wadeand Joyce Montet, et al., v. Edge Petroleum Corp of Texas, et al., consolidatedwith Rolland L. Broussard, et al., v. Edge Petroleum Corp of Texas, et al****.** - This is a consolidated suit, filed in state court inVermilion Parish, Louisiana in September 2003. Plaintiffs are mineral/royaltyowners under the Norcen-Broussard No. 1 and 2 wells, Marg Tex Reservoir C, SandUnit A (Edge’s old Bayou Vermilion Prospect).  They claim the operator atthe time, Norcen Explorer, now Anadarko, failed to “block squeeze” the sectionsof the No. 2 well, as a prudent operator, according to their allegations, wouldhave done, to protect the gas reservoir from being flooded with water fromadjacent underground formations. Plaintiffs further allege Norcen was negligentin not creating a field-wide unit to protect their interests.  The allegations relate to actions takenbeginning in the early 1990’s. Plaintiffs have named the Company and otherworking interest owners in the leases as defendants, including Norcen Explorer’ssuccessors in interest, Anadarko. Plaintiffs originally sought unspecifieddamages for lost royalties and damages due to alleged devaluation of theirmineral and property interests, plus interest and attorneys’ fees. In early2005, the Company filed a motion for summary judgment in the case asserting,among other defenses, that:  (i) there has been no breach of contract,(ii) there is no express or implied duty imposed on us to block squeeze thewell or form a field-wide unit, (iii) the units were properly formed by theConservation Commissioner in accordance with the statutory scheme in Louisiana,(iv) plaintiffs’ claims are barred by limitations, and (v) other defenses.Along with the other defendants, the Company also filed a special peremptorychallenge 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 us on the motion for summaryjudgment and the peremptory challenges. Of the 18.75% after-payout workinginterest that was originally reserved in the leases, the Company owned a 2.8%working interest at the time of the alleged acts or omissions. On September 6,2005, the Company filed a third-party demand to join the other working interestowners who hold the remainder of the 18.75% working interest as third-partydefendants in this case. These third-parties consist, for the most part, ofpartnerships that are directly or indirectly controlled by John Sfondrini, adirector of the Company, and hold an aggregate 14.7% working interest (the “SfondriniPartnerships”). Vincent Andrews, also a director of the Company, owns aminority interest in the corporate general partner of one of thepartnerships.  The Sfondrini Partnershipsconsist of (1) Edge Group

F-23

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Partnership, a general partnershipcomposed of limited partnerships of which Mr. Sfondrini and a companycontrolled by Mr. Sfondrini are general partners; (2) (A) Edge Option I LimitedPartnership, (B) Edge Option II Limited Partnership and (C) Edge Option IIILimited Partnership, limited partnerships of which Mr. Sfondrini and a companycontrolled by Mr. Sfondrini are general partners; and (3) BV Partners LimitedPartnership, a limited partnership of which a company controlled by Messrs.Sfondrini and Andrews is general partner and of which Mr. Sfondrini is manager(and of which company Mr. Andrews is an officer).  These partnerships were among the third partydefendants that the Company has sought to join in the case, and thesepartnerships have for the most part filed answers denying any liability to theCompany. The Company participated for its 2.8% share of the well costs andrevenues for the Broussard No. 2 well, as did the other defendants for theirshare, including the third-party defendant partnerships who participated for14.7%. The Company strongly believes the parties should only be liable fortheir proportionate share of any damages award should a finding of liabilityoccur in the case. The Company intends to vigorously contest the plaintiffs’ claims.

Asof the date of this report, it is not possible to determine what, if any, theCompany’s ultimate exposure might be in this matter. Prior to the settlementdescribed below, plaintiffs had asserted damages, including interest, to be ashigh as $63 million.  The plaintiffs’expert witness, in his December 2005 deposition, offered his theory thatplaintiffs’ gross damages are in the range of $19 to $22 million. That numberis based on his theory that the alleged failure to block squeeze the wellresulted in the under-production of gas worth $300 million. Plaintiffs’ royaltyshare 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 $3.75 million gross or net to our 2.8% sharewould be in the range of $560,000 (excluding interest and attorneys’ fees).Along with the other defendants, the Company hired its own expert witnesses whohave refuted these claims, particularly the expert’s assertions that failure toblock squeeze the well caused any damages to the reservoir. The deposition of aNorcen engineer who prepared the completion plan for the Broussard No. 2 welland supervised the completion operations, taken in April 2006, confirms thetestimony of the defense experts as to why the well was not blocksqueezed.  The plaintiffs have also retained a damages expert who hasgiven a report that the damages in this case are in the range of $30 million,excluding interest and attorneys’ fees. The Company’s share of that amount based on the full 18.75% would beapproximately $5.6 million and net to our 2.8% share would be approximately$840,000. The Company participated in mediation of this lawsuit on July 18,2006 but the parties failed to reach an agreement.  In July 2006, the plaintiffs’ attorney sent ademand to the defendants for total damages claimed by plaintiffs, with legalinterest, totaling $63 million.  TheCompany’s share of that amount based on the full 18.75% interest would be approximately$12.2 million and net to our 2.8% interest would be approximately $1.8 million.On July 31, 2006, the Judge granted the defendant groups’ motion for partialsummary judgment dismissing plaintiffs’ tort-based claims. Also on the samedate, the Judge granted the defendant groups’ motion for partial summaryjudgment seeking to deny the plaintiffs an award of attorneys’ fees and also todismiss any claim of plaintiffs that defendants had an obligation to form afield-wide unit.

*Broussard Plaintiff Settlement.*

OnDecember 19, 2006, the Company, along with the other defendants in this suit,reached a settlement agreement with the Broussard Plaintiffs in full settlementof their 72% of the total claims made in this consolidated action. Thissettlement was finalized in January 2007. The Company’s share of this settlement totaled approximately $208,000,which was recorded in December 2006, and the Sfondrini Partnerships’ sharetotaled $1,109,759.  The settlement withthe Broussard Plaintiffs was finalized on February 1, 2007, and the defendantsand the third-party defendants including the Sfondrini Partnerships werereleased from all claims by the Broussard Plaintiffs.

TheSfondrini Partnerships did not have sufficient cash to fund their respectivefull portion of the settlement. Therefore, in order to facilitate the settlement, the Company purchasedcertain oil and gas properties from certain of the Sfondrini Partnerships, withthe proceeds of such sale and purchase generally being directed to payment ofthe Broussard settlement, in full satisfaction of the Sfondrini Partnerships’share of such settlement.  The oil andgas properties that the Company purchased from the Sfondrini Partnerships andtheir respective purchase prices are as follows:

(1)   100%of each of Edge Group Partnership’s, Edge Option I Limited Partnership’s, EdgeOption II Limited Partnership’s and Edge Option III Limited Partnership’sinterest in the Ilse Miller No. 2 Well and leases, Wharton County, Texas, for atotal combined value of $51,243.

F-24

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(2)   100%of each of Edge Group Partnership’s, Edge Option I Limited Partnership’s, EdgeOption II Limited Partnership’s and Edge Option III Limited Partnership’sinterest in the Wm Baas 2-16 No. 1 Well and leases, Monroe County, Alabama, fora total combined value of $14,407.

(3)   55.953%of Edge Group Partnership’s interest in certain wells and leases in the Company’sAustin and Nita prospects, for a total value of $1,044,109.

Inthe purchase and sale transaction between us and the Sfondrini Partnerships, BVPartners Limited Partnership, whose 2.48% share of the Broussard settlementamount was $186,000 (as determined by the Company and Mr. Sfondrini on behalfof the BV Partners Limited Partnership), did not sell any assets to the Companyand did not have sufficient funds to satisfy their share of the settlementamount.  In addition, the Edge Option I,II and III Limited Partnerships did not have sufficient assets to satisfy theirrespective .34%, .34% and 2.25% shares of the settlement amount, which theCompany and Mr. Sfondrini determined to be $25,750, $25,750 and $169,102,respectively.  The shortfall amounts ofEdge Option I, II and III Limited Partnerships were, net of assets that theysold to the Company, determined by the Company and Mr. Sfondrini to be $24,333,$24,333 and $163,276, respectively.  As aresult, Edge Group Partnership sold additional properties (over the amountnecessary to fund its portion of the settlement) to the Company at fair marketvalue in an amount sufficient to allow it to have proceeds from such sale tofund BV Partners Limited Partnership’s share of the settlement and theremaining shortfall amounts owed by Edge Option I, II and III.  In return, BV Partners and Edge Option I, IIand III contributed all of their interest in the Bayou Vermilion Prospectleases and the Trahan No. 3 well located thereon to Edge GroupPartnership.  The fair market value ofthese interests contributed to Edge Group by BV Partners Limited Partnershipand Edge Option I, II and III were determined by the Company and Mr. Sfondrinion behalf of such partnerships to be $27,793, $3,847, $3,847 and $25,263,respectively.

Thevaluations of the interests of the Sfondrini Partnerships purchased by theCompany and the interests contributed to Edge Group Partnership by BV Partnersand Edge Option I, II and III were made at an agreed value, using a PV10 modeland assuming $7.50/MMBtu gas and $60/BBl oil, which the Company believedrepresented current pricing levels for oil and gas properties at the time, andwere agreed to by the Company and Mr. Sfondrini, on behalf of the SfondriniPartnerships.

The trial on theremaining claims, those of the Montet plaintiffs (approximately 28% of theoriginal aggregate claims in the case), is now set for trial beginning August27, 2007.  The Montet plaintiffs’calculation of their alleged damages has not changed.  If the jury were to adopt the plaintiffs’damage figures, the total damages attributable to the Montet plaintiffs couldbe approximately $17.6 million. The defendants’ exposure for an 18.75% share ofthat number would be approximately $3.31 million.  The exposure for the Company’s 2.8% sharewould be approximately $493,000.  Ifthere were a damage award against the defendants, the Company believes thatultimately it should only be liable for its 2.8% share of any such award unlessa co-party defendant, including any of the third-party defendants, cannotsatisfy their share of any final judgment or settlement amount or are found notto be liable to the Company on its third-party demand.  In that event, the Company could be heldresponsible for more than its 2.8% share. The Company believes it has meritorious defenses and intends to continueto vigorously contest this suit and its third-party demands against thepartnerships.  The Company has notestablished a reserve with respect to these claims.

TheCompany may have insurance coverage for all or part of this claim up to thepolicy limits of $1 million per occurrence and $2 million in theaggregate.  A claim was submitted toMid-Continent Casualty Company, our casualty carrier, who is currentlyproviding a defense under a reservation of rights letter.  However, on July 3, 2006, Mid-Continent fileda suit for declaratory judgment against us in federal district court inHouston, Texas seeking to determine whether it has a duty to indemnify theCompany and certain other defendants for this loss under the policies atissue.  Mid-Continent has asked the courtto declare they have no obligation to indemnify the Company and the third-partydefendants based on certain technical definitions under the policies and thefact that the plaintiffs’ claims are based on alleged breaches ofcontract.  The Company is both vigorouslydefending the declaratory judgment action, and actively seeking indemnity underthe policies at issue for its potential liabilities, if any, to the plaintiffsin the Louisiana actions.  The Company isalso pursuing coverage claims under other insurance policies that could cover aportion of our share of a loss in this case.

F-25

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**David Blake, et al. v. Edge Petroleum Corporation**– On September 19, 2005, David Blake and David Blake, Trustee of the David andNita Blake 1992 Children’s Trust filed suit against the Company in statedistrict court in Goliad County, Texas alleging breach of contract for failureand refusal to transfer overriding royalty interests to plaintiffs in at leastfive leases in Goliad County, Texas and failure and refusal to pay monies toBlake pursuant to such overriding royalty interests for wells completed on theleases. The plaintiffs seek relief of (1) specific performance of the allegedagreement, including granting of overriding royalty interests by the Company toBlake; (2) monetary damages for failure to grant the overriding royalty interests;(3) exemplary damages for his claims of business disparagement and slander; (4)monetary damages for tortuous interference; and (5) attorneys’ fees and courtcosts. Venue of the case was transferred to Harris County, Texas by agreementof the litigants.  The Company has servedplaintiffs with discovery and has filed a counterclaim and an amendedcounterclaim joining various related entities that are controlled byplaintiffs.  In addition, plaintiffs havefiled an amended complaint alleging claims of slander of title and tortuousinterference related to its alleged right to receive an overriding royaltyinterest from a third party.  Plaintiffscurrently have on file an amended motion for summary judgment, to which theCompany has filed a response.  Inaddition, the Company has filed a motion for summary judgment on the plaintiffs’case.  In December 2006, the court deniedthe Company’s motion for summary judgment. The court has not ruled on Blake’s motion.  The trial setting in March 2007 has been postponedby agreement of the parties and reset to September 15, 2007.  Discovery in the case has commenced and iscontinuing. The Company has responded aggressively to this lawsuit, andbelieves it has meritorious defenses and counterclaims.

**14.****       SALES TO MAJOR CUSTOMERSAND OPERATORS**

Inaccordance with SFAS No. 131, *Disclosuresabout Segments of an Enterprise and Related Information*, publicbusiness enterprises are required to report financial and other informationabout operating segments of the entity for which such information is availableand is utilized by the chief operating decision maker. SFAS No. 131 alsoestablishes standards for related disclosures about products and services,geographic area, and major customers. The Company operates as one businesssegment. We sold natural gas and crude oil production representing 10% or moreof our total revenues for the years ended December 31, 2006, 2005, and 2004 aslisted below:
|                               | ** ** | **For the Year Ended December 31,** | ** ** |
|-------------------------------|------------|--------------------------------------------------------------|------------|
| **Purchaser**                 | ** ** | **2006**                                                     | ** ** | **2005** | ** ** | **2004** | ** ** |
| Kinder Morgan                 |       | 37                                                           | %          | 29 | % | * |   |
| Chevron  Corporation          |       | 12                                                           | %          | 18 | % | 22 | % |
| Copano Field  Services        |       | 10                                                           | %          | 17 | % | 19 | % |
| Kerr-McGee Oil  & Gas     |       | 10                                                           | %          | * |   | * |   |
| Upstream Energy  Services (1) |       | 3                                                            | %          | 5 | % | 22 | % |

 

----

| * 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% are presented for information  and comparison purposes only. Also these percentages do not consider the  effects of financial derivative instruments. |

 

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.

F-26

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**15.****       INCOME TAXES**

Income tax expense,including deferred amounts, is summarized as follows:
|                | ** ** | **2006**                | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|----------------|------------|-------------------------|------------|------------|------------|------------|------------|
| ** **     | ** ** | **(in thousands)** | ** ** |
| **Current**    | ** ** | ** **              | ** ** | ** ** | ** ** | ** ** | ** ** |
| Federal        |       | $                       | 51         |       | $          | 327        |       | $ | — |   |
| State          |       | —                  |       | —     |       | —     |       |
| Total Current  |       | 51                      |       | 327        |       | —     |       |
| **Deferred**   | ** ** | ** **              | ** ** | ** ** | ** ** | ** ** | ** ** |
| Federal        |       | (21,959                 | )          | 17,751     |       | 8,255      |       |
| State          |       | 333                     |       | —     |       | —     |       |
| Total Deferred |       | (21,626                 | )          | 17,751     |       | 8,255      |       |
| **TOTAL**      |       | $                       | (21,575    | )          | $          | 18,078     |       | $ | 8,255 |   |

 

Total income taxesdiffered from the amounts computed by applying the statutory income tax rate toincome before income taxes.  The sourcesof these differences are as follows:
|                                                         | ** ** | **2006**                | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------------------------------------|------------|-------------------------|------------|----------|------------|----------|------------|
| ** **                                              | ** ** | **(in thousands)** | ** ** |
| Income (Loss)  Before Income Taxes                      |       | $                       | (62,836    | )        | $          | 51,436   |       | $ | 23,384 |   |
| Statutory tax  rate                                     |       | 35                      | %          | 35       | %          | 35       | %          |
|                                                    |       |                    |       |     |       |     |       |
| Tax computed on  statutory rate                         |       | $                       | (21,993    | )        | $          | 18,003   |       | $ | 8,184 |   |
| Adjustments  resulting from:                            |       |                    |       |     |       |     |       |
| State income taxes (net of federal income tax  benefit) |       | 333                     |       | —   |       | —   |       |
| Expenses not deductible for tax purposes and other      |       | 85                      |       | 75       |       | 71       |       |
| Total income tax  expense (benefit)                     |       | $                       | (21,575    | )        | $          | 18,078   |       | $ | 8,255 |   |
| Effective tax rate                                      |       | 34.3                    | %          | 35.2     | %          | 35.3     | %          |

 

The effect of stock-basedcompensation expense for tax purposes in excess of amounts recognized forfinancial accounting purposes has been credited directly to stockholders’equity in the amounts of approximately $461,900, $507,300 and $462,000 for2006, 2005 and 2004, respectively.

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 this method, future income tax assetsand liabilities are determined based on the “temporary differences” between theaccounting basis and the income tax basis of the Company’s assets andliabilities measured using the currently enacted, or substantially enacted,income tax rates in effect when these differences are expected to reverse.Significant components of the Company’s deferred tax liabilities and assets asof December 31, 2006 and 2005 are as follows:

F-27

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|                                                                      | ** ** | **As of December 31,** | ** ** |
|----------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                           | ** ** | **2006**                              | ** ** | **2005** | ** ** |
| ** **                                                           | ** ** | **(in thousands)**               | ** ** |
| Deferred tax  liability – current:                              |       |                                  |       |   |   |
| Price-risk management liability                                      |       | $                                     | (1,816     | ) | $ | (252 | ) |
| Deferred tax  asset – current:                                  |       |                                  |       |   |   |
| Price-risk management                                                |       | —                                |       | 922 |   |
| Compensation cost                                                    |       | 894                                   |       | 1,076 |   |
| Expenses not currently deductible for tax purposes                   |       | 289                                   |       | 542 |   |
| Other                                                                |       | 200                                   |       | 230 |   |
| Total deferred tax asset – current                              |       | 1,383                                 |       | 2,770 |   |
| Net deferred tax asset (liability) – current                    |       | $                                     | (433       | ) | $ | 2,518 |   |
|                                                                 |       |                                  |       |   |   |
| Deferred tax  liability – long-term:                            |       |                                  |       |   |   |
| Book basis of oil and natural gas properties in  excess of tax basis |       | $                                     | (37,807    | ) | $ | (58,247 | ) |
| Deferred tax  asset – long-term:                                |       |                                  |       |   |   |
| Net operating loss carryforwards                                     |       | 25,956                                |       | 19,532 |   |
| Accretion on ARO                                                     |       | 246                                   |       | 180 |   |
| Federal alternative minimum tax credits                              |       | 497                                   |       | 445 |   |
| Other                                                                |       | 197                                   |       | 193 |   |
| Total deferred  tax asset – long-term                           |       | 26,896                                |       | 20,350 |   |
| Net deferred tax  liability – long-term                         |       | $                                     | (10,911    | ) | $ | (37,897 | ) |

 

Total deferred taxes at December 31, 2006 includestate deferred taxes of approximately $333,000. No state deferred taxes were included at December 31, 2005.

Tax carryforwards at December 31, 2006, which areavailable for utilization on future income tax returns, are as follows:
|                                        | ** ** | **Domestic**            | ** ** | **Expiration** | ** **  |
|----------------------------------------|------------|-------------------------|------------|----------------|-------------|
| ** **                             | ** ** | **(in thousands)** | ** ** | ** **     | ** **  |
| Net operating  loss – regular tax |       | $                       | 73,553     |           | 2012 - 2026 |   |
| Net operating loss -  state            |       | $                       | 465        |           | 2007 - 2017 |   |

 

The Company believesthat it is more likely than not that it will utilize all of these NOLs inconnection with federal income taxes generated in the future.  The estimated NOLs presented herein assumethat certain items, primarily intangible drilling costs, have been written offfor tax purposes in the current year. However, the Company has not made a final determination if an electionwill be made to capitalize all or part of these items for tax purposes in thefuture.

**16.****       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 orolder.  The Company’s matchingcontributions to the Plan are discretionary. For the years ended December 31, 2006, 2005 and 2004, the Companycontributed approximately $480,300, $176,500, and $121,300, respectively, tothe Plan.  In 2006, the Company increasedthe percentage of employee contributions that it matches, which accounts forthe significant increase between 2005 and 2006.***

**17.****       EQUITY AND STOCK PLANS**

***Private Offering –***In connection with a private offering on May 6, 1999 of 1,400,000 shares ofcommon stock at a price of $5.40 per share, the Company issued warrants for$0.125 per warrant, to acquire an additional 420,000 shares of common stock at$5.35 per share and were exercisable through May 6, 2004. All of these warrantshave now been exercised. At the election of the Company, the warrants could havebeen called at a redemption price of $0.01 per warrant at any time after anydate at which the average daily per share closing bid price for the immediatelypreceding 20 consecutive trading days exceeds $10.70.  In November and December of 2003, 375,000 warrantswere exercised for proceeds of approximately $2.0 million.  In March 2004, Mr. Elias, our Chairman andChief Executive Officer, exercised the remaining warrants, which resulted inthe Company’s issuance to him of 45,000 shares of common stock and net proceedsto us of $240,750.

F-28

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***Public Offering*** ***–*** In connection with a public offering onDecember 21, 2004, the Company issued 3.5 million shares of common stock at agross price of $14.45 per share. This offering generated net proceeds to us,after underwriter’s fees and before direct costs of the offering, of $47.8million. These shares were issued to generate funds to finance the ContangoAsset Acquisition that was completed December 29, 2004. In January 2005, theunderwriters exercised their overallotment option for 0.5 million additionalshares of common stock, resulting in an additional $7.2 million of net proceedsto the Company.

***Share-Based Compensation***– The Company established the IncentivePlan of Edge Petroleum Corporation (the “Incentive Plan”) in conjunction withits initial public offering in March 1997. 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 and restricted stock granted todate vest over periods of 2 to 4 years. The Company amended the Incentive Plan (i) in December 2003 to increase theshares available under the plan from 1.2 million shares to 1.7 million sharesand (ii) in June 2006 to increase the number of shares available under thePlan from 1.7 million shares to 2.2 million shares.  Of the aggregate 2.2 million shares of commonstock reserved for grants under the Incentive Plan, 501,446 shares wereavailable for future grants at December 31, 2006.  The following nonqualified stock optionawards and restricted stock unit grants were made under the Incentive Planduring each of the years indicated below:
|                                     | ** **   | **Number  Granted** | ** **   | **Market Value on  Date of Grant** | ** **   |
|-------------------------------------|--------------|---------------------|--------------|--------------------------------------------------------|--------------|
| ***Options  Awards:***              | *** *** | *** ***        | *** *** | *** ***                                           | *** *** |
| 2006                                |         | —              |         | —                                                 |         |
| 2005                                |         | —              |         | —                                                 |         |
| 2004                                |         | 13,000              |         | $13.99                                                 |         |
|                                |         |                |         |                                                   |         |
| ***Restricted  Stock Awards (1):*** | *** *** | *** ***        | *** *** | *** ***                                           | *** *** |
| 2006                                |         | 326,280             |         | $16.42 to $32.40                                       |         |
| 2005                                |         | 131,640             |         | $14.02 to $25.12                                       |         |
| 2004                                |         | 94,676              |         | $10.09 to $16.89                                       |         |

 

----

(1)          Restricted stock awards granted, as presentedabove, are net of shares forfeited or cancelled during the corresponding year.

As acomponent 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 options and restricted stock under the IncentivePlan.  The options vest and becomeexercisable over a two or three year period subsequent to issue.  The restricted stock is issued ratably overthree years in accordance with the award’s vesting schedule, beginning on thefirst anniversary of the date of grant. Compensation expense is amortized over the vesting period and offset toadditional paid in capital (“APIC”).  Theamortization of compensation expense related to this award is included ingeneral and administrative expenses on the consolidated statement ofoperations.  Below is a summary of optionsand restricted stock grants made to Mr. Elias outside of the Incentive Plan:
| **Date Granted**        | ** **   | **Shares  Outstanding** | ** **   | **Exercise  Price** | ** **   | **Date Exercisable**                                                         | ** **                                                                |
|------------------------------|--------------|-------------------------|--------------|---------------------|--------------|-----------------------------------------------------------------------------------|---------------------------------------------------------------------------|
| *** ***                 | *** *** | *** ***            | *** *** | *** ***        | *** *** | *** ***                                                                      | *** ***                                                              |
| ***Options  (1):***          | *** *** | *** ***            | *** *** | *** ***        | *** *** | *** ***                                                                      | *** ***                                                              |
| 01/08/1999                   |         | 200,000                 |         | $                   | 4.22         |                                                                              | One-third  upon issue and one-third upon each of January 1, 2000 and 2001 |   |
| 01/03/2000                   |         | 50,000                  |         | $                   | 3.16         |                                                                              | 100%  January 2002                                                        |   |
| 01/03/2001                   |         | 50,000                  |         | $                   | 8.88         |                                                                              | 100%  January 2003                                                        |   |
| 01/03/2002                   |         | 50,000                  |         | $                   | 5.18         |                                                                              | 100%  January 2004                                                        |   |
| 04/02/2002                   |         | 24,000                  |         | $                   | 5.59         |                                                                              | 100%  April 2004                                                          |   |
| 01/23/2003                   |         | 50,000                  |         | $                   | 3.88         |                                                                              | 100%  January 2005                                                        |   |
| 04/01/2004                   |         | 37,000                  |         | $                   | 13.99        |                                                                              | 100%  January 2006                                                        |   |
|                         |         |                    |         |                |         |                                                                              |                                                                      |
| ***Restricted  Stock (2):*** | *** *** | *** ***            | *** *** | *** ***        | *** *** | *** ***                                                                      | *** ***                                                              |
| 04/02/2001                   |         | 14,000                  |         |                |         | Ratably  over three years beginning on the first anniversary of the date of grant |                                                                      |

 

F-29

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(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.

EffectiveJanuary 1, 2006, the Company adopted SFAS No. 123(R) utilizing the modifiedprospective approach.  Prior to theadoption of SFAS No. 123(R), the Company accounted for stock option grants inaccordance with APB No. 25 using theintrinsic value method, and accordingly, recognized no compensation expense forstock option grants.  In 1999, theCompany repriced certain employee and director stock options.  The Company accounted for these repricedstock options in accordance with FIN 44 which prescribed the variable planaccounting treatment for repriced options. Under variable plan accounting, compensation expense is adjusted forincreases or decreases in the fair market value of the Company’s common stockto the extent that the market value exceeds the exercise price of the optionuntil the options are exercised, forfeited, or expire unexercised.

Underthe modified prospective approach, SFAS No. 123(R) applies to new awards and toawards that were outstanding on January 1, 2006 that are subsequently modified,repurchased or cancelled.  Under themodified prospective approach, compensation cost recognized in the first quarterof fiscal 2006 includes compensation cost for all share-based payments grantedprior to, but not yet vested, as of January 1, 2006, based on the grant-datefair value estimated in accordance with the original provisions of SFAS No. 123and compensation cost for all share-based payments granted subsequent toJanuary 1, 2006, based on the grant-date fair value estimated in accordancewith the provisions of SFAS No. 123(R). Prior periods were not restated to reflect the impact of adopting thenew standard.

Share-based compensationcosts for the years ended December 31, 2006, 2005 and 2004 were:
|                                 | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------|------------|--------------------------------------------|------------|
| ** **                      | ** ** | **2006 (1)**                          | ** ** | **2005 (2)(3)** | ** ** | **2004 (2)(3)** | ** ** |
| ** **                      | ** ** | **(in thousands)**                    | ** ** |
|                            |       |                                       |       |   |   |   |   |
| Stock options                   |       | $                                          | 69         |   | $ | — |   | $ | — |   |
|                            |       |                                       |       |   |   |   |   |
| Repriced stock  options (2)     |       | —                                     |       | 1,628 |   | 1,136 |   |
|                            |       |                                       |       |   |   |   |   |
| Restricted stock  units         |       | 1,908                                      |       | 974 |   | 498 |   |
|                            |       |                                       |       |   |   |   |   |
| Total share-based  compensation |       | $                                          | 1,977      |   | $ | 2,602 |   | $ | 1,634 |   |

 

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| (1) In accordance with SFAS No. 123(R). |   |   |   |   |
|-----------------------------------------|--------|--------|--------|--------|
| (2) In accordance with FIN  44.         |   |   |   |   |
| (3) In accordance with APB  No. 25.     |   |   |   |   |

 

As aresult of adopting SFAS No. 123(R), the Company’s loss before income taxes andnet loss for 2006 was approximately $301,400 and $195,900 lower, respectively,than if the Company had continued to account for share-based compensation underAPB No. 25.  Basic and diluted loss pershare for the year ended December 31, 2006 would have been $(2.36) if theCompany had not adopted SFAS No. 123(R), compared to reported basic and dilutedloss per share of $(2.38).

TheCompany receives a tax deduction for certain stock options exercised during theperiod the options are exercised, generally for the excess of the price atwhich the options are sold over the exercise prices of the options.  In addition, the Company receives a taxdeduction for restricted stock grants that vest during the period for theexcess of the fair value on the vesting date compared to the grant date fairvalue.  SFAS No. 123(R) requires thatthese excess tax benefits be reported in the consolidated statement of cashflows as financing activities.  SFAS No.123(R) provides that the excess tax benefit and credit to APIC for the windfallshould not be recorded until the

F-30

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deduction reducesincome taxes payable.  Because theCompany is in a net operating loss (“NOL”) position for tax purposes, and doesnot have taxes payable at this time, it has not realized a tax benefit from thededuction.  Therefore, the Companyexcludes these deductions from the windfall pool and does not present the taxbenefits from the exercise of stock options as financing activities.  As of December 31, 2006, $1.6 million of NOLcarryforwards will be credited to APIC in future periods when the tax benefitis realized and reduces taxes payable.

# **Stock Options**

There have been no stockoption grants in 2006 or 2005.  Forfuture grants, the Company expects to use the Black-Scholes option pricingmodel to estimate the fair value of stock options which requires the Company tomake the following assumptions:

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

·                  The dividendyield on the Company’s common stock is assumed to be zero since the Companydoes not pay dividends.

·                  The market pricevolatility of the Company’s common stock is based on historical prices.

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

Theassumptions above are based on multiple factors, including historical exercisepatterns of employees in relatively homogenous groups with respect to exerciseand post-vesting employment termination behaviors, expected future exercisingpatterns for these same homogeneous groups and the implied volatility of ourstock price.

Inaddition, the Company estimates a forfeiture rate at the inception of theoption grant based on historical data and adjusts this prospectively as newinformation regarding forfeitures becomes available.

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

Asummary of activity associated with the Company’s stock options during the lastthree years follows:
| ** **                             | ** ** | **Number of  Shares** | ** ** | **Weighted  Average Exercise  Price** | ** ** | **Weighted  Average  Remaining  Contract Life** | ** ** | **Aggregate  Intrinsic Value** | ** ** |
|----------------------------------------|------------|----------------------------|------------|--------------------------------------------|------------|------------------------------------------------------|------------|-------------------------------------|------------|
| For the Year  Ended December 31, 2004: |       |                       |       |                                       |       |                                                 |       |                                |       |
| Outstanding, beginning of period       |       | 1,171,512                  |       | $                                          | 8.76       |                                                 |       |                                |       |   |
| Granted                                |       | 50,000                     |       | 13.99                                      |       |                                                 |       |                                |       |
| Exercised                              |       | (322,723                   | )          | 6.24                                       |       |                                                 |       |                                |       |
| Forfeited                              |       | (76,739                    | )          | 59.11                                      |       |                                                 |       |                                |       |
| Outstanding, end of period             |       | 822,050                    |       | 5.91                                       |       | 5.79 years                                           |       | $                                   | 7,195,268  |   |
| Exercisable, end of period             |       | 690,050                    |       | 5.51                                       |       | 5.26 years                                           |       | $                                   | 6,316,658  |   |
| For the Year  Ended December 31, 2005: |       |                       |       |                                       |       |                                                 |       |                                |       |
| Outstanding, beginning of period       |       | 822,050                    |       | 5.91                                       |       |                                                 |       |                                |       |
| Exercised                              |       | (86,600                    | )          | 5.67                                       |       |                                                 |       |                                |       |
| Outstanding, end of period             |       | 735,450                    |       | 5.93                                       |       | 4.80 years                                           |       | $                                   | 13,760,616 |   |
| Exercisable, end of period             |       | 685,450                    |       | 5.35                                       |       | 4.55 years                                           |       | $                                   | 13,227,866 |   |
| For the Year Ended  December 31, 2006: |       |                       |       |                                       |       |                                                 |       |                                |       |
| Outstanding, beginning of period       |       | 735,450                    |       | 5.93                                       |       |                                                 |       |                                |       |
| Exercised                              |       | (84,750                    | )          | 6.80                                       |       |                                                 |       |                                |       |
| Outstanding, end of period             |       | 650,700                    |       | 5.82                                       |       | 3.92 years                                           |       | $                                   | 8,200,945  |   |
| Exercisable, end  of period            |       | 650,700                    |       | $                                          | 5.82       |                                                 | 3.92 years |                                | $          | 8,200,945 |   |

 

F-31

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Thefair value of options was measured at the date of grant using the Black-Scholesoption-pricing model.  There were nooptions granted or forfeited for the years ended December 31, 2006 and 2005.  For the year ended December 31, 2004, theweighted-average fair value of options granted during the year was $11.03 usingthe following weighted-average assumptions:
|                                                                                    | ** ** | **For the Year Ended  December 31, 2004** | ** ** |
|------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------|------------|
| Risk free  interest rate                                                           |       | 3.76%                                                              |       |
| Dividend yield                                                                     |       | None                                                               |       |
| Volatility  factor of the expected market price of the Company’s common stock |       | 72%                                                                |       |
| Expected life of the  options (in years)                                           |       | 10                                                                 |       |

 

TheBlack-Scholes option valuation model was developed for use in estimating thefair value of traded options that have no vesting restrictions and are fullytransferable.  In addition, optionvaluation models require the input of highly subjective assumptions includingthe expected stock price volatility.  TheCompany’s stock options have characteristics significantly different for thoseof traded options and because changes in the subjective input assumptions canmaterially affect the fair value estimate, it is management’s opinion that thevaluations afforded by the existing models are different from the value thatthe options would realize if traded in the market.

Asummary of additional information related to options outstanding as of December31, 2006 follows:
| **All Options**                   | ** ** | **Options Exercisable** | ** ** |
|----------------------------------------|------------|------------------------------|------------|
| **Range of  Exercise Price** | ** ** | **Options  Outstanding**     | ** ** | **Weighted  Average  Remaining  Contractual Life  (in years)** | ** ** | **Weighted  Average  Exercise  Price** | ** ** | **Range of  Exercise  Price** | ** ** | **Options  Outstanding** | ** ** | **Weighted  Average  Exercise  Price** | ** ** |
| $3.00 - $3.88                          |       | 119,500                      |       | 4.60 |   | $ | 3.52 |   | $3.00-$3.88 |   | 119,500 |   | $ | 3.52 |   |
| $4.22                                  |       | 200,000                      |       | 2.00 |   | $ | 4.22 |   | $4.22 |   | 200,000 |   | $ | 4.22 |   |
| $5.18 - $5.73                          |       | 160,500                      |       | 5.33 |   | $ | 5.46 |   | $5.18-$5.73 |   | 160,500 |   | $ | 5.46 |   |
| $7.06 - $7.58                          |       | 70,600                       |       | 2.59 |   | $ | 7.12 |   | $7.06-$7.58 |   | 70,600 |   | $ | 7.12 |   |
| $8.88                                  |       | 50,000                       |       | 4.00 |   | $ | 8.88 |   | $8.88 |   | 50,000 |   | $ | 8.88 |   |
| $13.50-$13.99                          |       | 50,100                       |       | 7.24 |   | $ | 13.99 |   | $13.50-$13.99 |   | 50,100 |   | $ | 13.99 |   |

 

# **Restricted Stock**

Inaddition to stock options, the Company issues restricted stock and restrictedstock units.  For awards issued to date,shares of common stock associated with the restricted stock awards will beissued, subject to continued employment, ratably over three or four years inaccordance with the award’s vesting schedule, beginning on the first or secondanniversary of the date of grant. Compensation expense from restricted stock and restricted stock units isamortized over the vesting period and offset to APIC.  The share-based expense for these awards wasdetermined based on the market price of the Company’s stock at the date ofgrant applied to the total number of shares that were anticipated to fully vestand then amortized over the vesting period. As of December 31, 2006, the Company had unamortized share-basedcompensation of $5.8 million associated with these awards.  The cost is expected to be

F-32

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recognized over aweighted-average period of two years. The total fair value of shares vested during the year ended December 31,2006 was $2.3 million.  Upon adoption ofSFAS No. 123(R), the Company recorded an immaterial cumulative effect of changein accounting principle as a result of the change in policy from recognizingforfeitures as they occur to recognizing expense based on its expectation ofthe awards that will vest over the requisite service period for its restrictedstock and restricted stock unit awards. This amount was recorded as compensation cost in general andadministrative expenses in the consolidated statement of operations.

Thefollowing table below summarizes restricted stock activity for the year endedDecember 31, 2006:
|                                                       | ** ** | **Shares** | ** ** | **Weighted-  Average Price** | ** ** |
|-------------------------------------------------------|------------|------------|------------|-----------------------------------|------------|
| Unvested  restricted stock units at December 31, 2005 |       | 218,954    |       | $                                 | 14.90      |   |
| Granted                                               |       | 333,600    |       | 19.32                             |       |
| Vested                                                |       | (98,720    | )          | 13.14                             |       |
| Forfeited                                             |       | (17,210    | )          | 21.02                             |       |
| Unvested restricted  stock units at December 31, 2006 |       | 436,624    |       | $                                 | 18.43      |   |

 

***Computation ofEarnings per Share -***The following is presented as areconciliation of the numerators and denominators of basic and diluted earnings(loss) per share computations, in accordance with SFAS No. 128.
|                                                     | ** ** | **Year Ended December 31,**                              | ** ** |
|-----------------------------------------------------|------------|-------------------------------------------------------------------------|------------|
| ** **                                          | ** ** | **2006**                                                                | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                          | ** ** | ***(in thousands, except per share amounts)*** | ** ** |
| Net income (loss)                                   |       | $                                                                       | (41,261    | ) | $ | 33,358 |   | $ | 15,129 |   |
|                                                |       |                                                                    |       |   |   |   |   |
| Basic weighted average  shares outstanding          |       | 17,368                                                                  |       | 17,122 |   | 13,029 |   |
| Add: dilutive effect of  employee stock options     |       | —                                                                  |       | 498 |   | 477 |   |
| Add: dilutive effect of  restricted stock units     |       | —                                                                  |       | 195 |   | 142 |   |
| Diluted  weighted-average common shares outstanding |       | 17,368                                                                  |       | 17,815 |   | 13,648 |   |
|                                                |       |                                                                    |       |   |   |   |   |
| Basic income (loss) per  common share               |       | $                                                                       | (2.38      | ) | $ | 1.95 |   | $ | 1.16 |   |
| Diluted income (loss) per common share              |       | $                                                                       | (2.38      | ) | $ | 1.87 |   | $ | 1.11 |   |

 

Associated with the exercise of stock options, theCompany received a tax benefit of approximately $461,900, $507,300 and $462,000in 2006, 2005 and 2004, respectively. The tax benefit is recorded as anincrease in additional paid-in capital.

**18.****                               RELATEDPARTY 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, a Connecticut general partnership composed of thethree Connecticut limited partnerships (Edge I, L.P., Edge II, L.P., and EdgeIII, L.P.) whose general partners are Mr. Sfondrini and a corporationwholly-owned by him; Edge Holding Company, L.P., a limited partnership of whichMr. Sfondrini and a corporation wholly owned by him are the general partners;Andex Energy Corporation and Texedge Energy Corporation, corporations of whichMr. Andrews is an officer and members of his immediate family hold ownershipinterests, Mr. Raphael (a director of the Company), Jovin, L.P. (a limitedpartnership, the general partners of which are a company wholly owned by Mr.Sfondrini and a company of which Mr. Andrews is an officer) and Essex II JointVenture, own certain working interests in the Company’s Nita and AustinProspects and certain other wells and prospects operated by the Company. Theseworking interests aggregate 7.19% in the Austin Prospect, 6.27% in the NitaProspect and are neglible in other wells and prospects. These working interests

F-33

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bear their shareof lease operating costs and royalty burdens on the same basis as the Company.In addition, Bamaedge, L.P., a limited partnership of which Andex EnergyCorporation is the general partner, and Mr. Raphael also hold overridingroyalty interests with respect to the Company’s working interest in certainwells and prospects.  Neither Mr. Raphaelnor Bamaedge L.P. has an overriding interest in excess of 0.075% in any onewell or prospect. Essex I Joint Venture and Essex II Joint Venture (a jointventure of which Mr. Sfondrini and a company wholly owned by him are themanagers) own royalty and overriding royalty interests in various wellsoperated by the Company. The combined royalty and overriding royalty interestsof the Essex I and Essex II Joint Ventures do not exceed 6.2% in any one wellor prospect. In September 2006, the Essex I and Essex II Joint Ventures soldall of their interests in wells operated by the Company except for one well inwhich Essex II has a 1% gross working interest. The gross amounts paid or accrued to these persons and entities by theCompany in 2006 (including net revenue, royalty and overriding royalty interests)and the amounts these same persons and entities paid to the Company for theirrespective share of lease operating expenses and other costs is set forth inthe following table:
| ** **                              | ** ** | **Total Amounts Paid by the Company to Owners Including   Overriding Royalty (1)** | ** ** |
|-----------------------------------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------|------------|
| **Owner**                               | ** ** | **2006**                                                                                                                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| Andex Corporation  /Texedge Corporation |       | $                                                                                                                                         | 4,375      |   | $ | 2,516 |   | $ | 3,896 |   |
| Bamaedge, L.P.                          |       | 1,447                                                                                                                                     |       | 2,057 |   | 3,594 |   |
| Edge Group  Partnership                 |       | 428,321                                                                                                                                   |       | 291,773 |   | 387,603 |   |
| Edge Holding  Co., L.P.                 |       | 76,169                                                                                                                                    |       | 54,048 |   | 71,177 |   |
| Essex I Royalty  Joint Venture          |       | 18,641                                                                                                                                    |       | 23,887 |   | 32,603 |   |
| Essex II Royalty  Joint Venture         |       | 112,912                                                                                                                                   |       | 79,781 |   | 150,509 |   |
| Jovin, L.P.                             |       | —                                                                                                                                    |       | — |   | — |   |
| Stanley Raphael                         |       | 4,268                                                                                                                                     |       | 3,630 |   | 5,209 |   |
| **Total**                               |       | $                                                                                                                                         | 646,133    |   | $ | 457,692 |   | $ | 654,591 |   |

 

----

(1)    In the caseof Essex I and II Royalty Joint Ventures, amount includes royalty income in additionto working interest and overriding royalty income. The Company sold itsinterest in these entities in 2003, but Mr. Sfondrini, maintains an indirectinterest in these entities.
| ** **                              | ** ** | **Lease Operating Expenses Paid to the Company by Owners** | ** ** |
|-----------------------------------------|------------|----------------------------------------------------------------------------------------------------|------------|
| **Owner**                               | ** ** | **2006**                                                                                           | ** ** | **2005** | ** ** | **2004** | ** ** |
| Andex  Corporation /Texedge Corporation |       | $                                                                                                  | —     |   | $ | — |   | $ | 2,578 |   |
| Bamaedge, L.P.                          |       | 318                                                                                                |       | — |   | — |   |
| Edge Group  Partnership                 |       | 308,516                                                                                            |       | 66,146 |   | 40,284 |   |
| Edge Holding  Co., L.P.                 |       | 54,422                                                                                             |       | 12,711 |   | 7,065 |   |
| Essex I Royalty  Joint Venture          |       | —                                                                                             |       | — |   | — |   |
| Essex II Royalty  Joint Venture         |       | 64,248                                                                                             |       | 13,114 |   | 5,629 |   |
| Jovin, L.P.                             |       | —                                                                                             |       | — |   | — |   |
| Stanley Raphael                         |       | 2,595                                                                                              |       | 659 |   | 412 |   |
| **Total**                               |       | $                                                                                                  | 430,099    |   | $ | 92,630 |   | $ | 55,968 |   |

 

**19.          SUPPLEMENTAL DISCLOSURE OF NON-CASHINVESTING AND FINANCING ACTIVITIES**

A summary ofnon-cash investing and financing activities for the years ended December 31,2006, 2005 and 2004 is presented below:

F-34

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| Description                                                                                          | ** **   | **Number   of shares   issued** | ** **   | **Fair Market   Value** | ** **   |
|------------------------------------------------------------------------------------------------------|--------------|------------------------------------------------|--------------|-----------------------------------|--------------|
| ** **                                                                                           | *** *** | ***(in thousands)***                      | *** *** |
| **2006:**                                                                                            | *** *** | *** ***                                   | *** *** | *** ***                      | *** *** |
| Shares issued to  satisfy restricted stock grants                                                    |         | 119                                            |         | $                                 | 1,803        |   |
| Shares issued to fund  the Company’s matching contribution under the Company’s 401(k) plan |         | 22                                             |         | $                                 | 429          |   |
| **2005:**                                                                                            |         |                                           |         |                              |         |
| Shares  issued to satisfy restricted stock grants                                                    |         | 59                                             |         | $                                 | 570          |   |
| Shares issued to fund  the Company’s matching contribution under the Company’s 401(k) plan |         | 10                                             |         | $                                 | 168          |   |
| **2004:**                                                                                            |         |                                           |         |                              |         |
| Shares  issued to satisfy restricted stock grants                                                    |         | 70                                             |         | $                                 | 447          |   |
| Shares issued to fund the Company’s matching contribution under the  Company’s 401(k) plan |         | 8                                              |         | $                                 | 112          |   |

 

For the years endedDecember 31, 2006, 2005 and 2004, the non-cash portion of Asset RetirementCosts was $0.4 million, $0.4 million, and $0.3 million, respectively.  A supplemental disclosure of cash flowinformation for the years ended December 31, 2006, 2005 and 2004 is presentedbelow:
|                                           | ** **   | **For the Year Ended December 31,** | ** **   |
|-------------------------------------------|--------------|--------------------------------------------------------------|--------------|
| ** **                                | ** **   | **2006**                                                     | ** **   | **2005** | ** ** | **2004** | ** ** |
| ** **                                | *** *** | ***(in thousands)***                                    | *** *** |
| Cash paid during the  period for:         |         |                                                         |         |   |   |   |   |
| Interest, net of  amounts capitalized     |         | $                                                            | 1,959        |   | $ | — |   | $ | 331 |   |
| Federal alternative  minimum tax payments |         | 94                                                           |         | 327 |   | — |   |
|                                           |              |                                                              |              |  |  |  |  |  |  |  |

 

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

The sum of theindividual quarterly basic and diluted earnings (loss) per share amounts maynot agree with year-to-date basic and diluted earnings (loss) per share amountsas a result of each period’s computation being based on the weighted averagenumber of common shares outstanding during that period.
| ** **                         | ** ** | **Fourth  Quarter**                                                     | ** ** | **Third  Quarter (1)** | ** ** | **Second  Quarter** | ** ** | **First  Quarter** | ** ** |
|------------------------------------|------------|-------------------------------------------------------------------------|------------|-----------------------------|------------|---------------------|------------|--------------------|------------|
| ** **                         | ** ** | ***(in thousands, except per share amounts)*** | ** ** |
| **2006:**                          |       |                                                                    |       |                        |       |                |       |               |       |
| Oil and natural  gas revenue       |       | $                                                                       | 24,931     |                        | $          | 35,941              |       | $                  | 33,878     |   | $ | 34,994 |   |
| Operating  expenses                |       | (19,364                                                                 | )          | (122,619                    | )          | (24,389             | )          | (23,695            | )          |
| Operating income  (loss)           |       | 5,567                                                                   |       | (86,678                     | )          | 9,489               |       | 11,299             |       |
| Other expense,  net                |       | (478                                                                    | )          | (809                        | )          | (554                | )          | (672               | )          |
| Income tax  (expense) benefit      |       | (2,157                                                                  | )          | 30,607                      |       | (3,140              | )          | (3,735             | )          |
| Net income  (loss)                 |       | $                                                                       | 2,932      |                        | $          | (56,880             | )          | $                  | 5,795      |   | $ | 6,892 |   |
| Basic earnings  (loss) per share   |       | $                                                                       | 0.17       |                        | $          | (3.27               | )          | $                  | 0.33       |   | $ | 0.40 |   |
| Diluted earnings  (loss) per share |       | $                                                                       | 0.16       |                        | $          | (3.27               | )          | $                  | 0.32       |   | $ | 0.38 |   |
| **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          |       | $                                                                       | 0.77       |                        | $          | 0.47                |       | $                  | 0.42       |   | $ | 0.28 |   |
| Diluted earnings per  share        |       | $                                                                       | 0.74       |                        | $          | 0.45                |       | $                  | 0.41       |   | $ | 0.27 |   |

 

----

(1)    Operatingexpenses in the third quarter of 2006 include a $96.9 million ($63.0 million,net of tax) non-cash impairment charge as a result of a full-cost ceiling testwrite down.  See the full-cost ceilingtest discussion in Note 2.

F-35

----

 

**21****                                  SUPPLEMENTARYFINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTIONACTIVITIES (unaudited)**

This footnote provides unaudited information requiredby SFAS No. 69, *Disclosures About Oil andNatural Gas Producing Activities*. The Company’s oil and natural gasproperties are located within the United States of America, which constitutesone cost center.

***Capitalized Costs -***Capitalizedcosts and accumulated depletion relating to the Company’s oil and natural gasproducing activities, all of which are conducted within the continental UnitedStates, are summarized below:
|                                             | ** ** | **As of December 31,** | ** ** |
|---------------------------------------------|------------|---------------------------------------|------------|
| ** **                                  | ** ** | **2006**                              | ** ** | **2005** | ** ** |
| ** **                                  | ** ** | ***(in thousands)***             | ** ** |
| Developed oil  and natural gas properties   |       | $                                     | 521,713    |   | $ | 401,697 |   |
| Unevaluated oil  and natural gas properties |       | 57,577                                |       | 36,949 |   |
| Accumulated  depletion                      |       | (290,863                              | )          | (133,449 | ) |
| Net capitalized cost                        |       | $                                     | 288,427    |   | $ | 305,197 |   |

 

***Costs Incurred******-***Costs****incurred in oil and natural gas property acquisition,exploration and development activities are summarized below:
|                        | ** **   | **For the Year Ended December 31,** | ** **   |     |
|------------------------|--------------|--------------------------------------------------------------|--------------|----------|
| ** **             | ** **   | **2006**                                                     | ** **   | **2005** | ** ** | **2004** | ** ** |   |
| ** **             | *** *** | ***(in thousands)***                                    | *** *** |     |
| Acquisition cost: |         |                                                         |         |     |   |   |   |
| Unproved properties    |         | $                                                            | 21,661       |     | $ | 33,948 |   | $ | 12,163 |   |   |
| Proved properties (1)  |         | 36,573                                                       |         | 66,472   |   | 33,980 |   |   |
| Exploration  costs     |         | 17,898                                                       |         | 20,426   |   | 8,297 |   |   |
| Development  costs (2) |         | 65,140                                                       |         | 59,121   |   | 34,827 |   |   |
| Total costs  incurred  |         | $                                                            | 141,272      |     | $ | 179,967 |   | $ | 89,267 |   |   |
|                        |              |                                                              |              |          |  |  |  |  |  |  |  |  |  |  |  |  |

 

----

(1)                Includes $17.8 million added to propertyacquired in the Cinco acquisition in 2005 associated with recording a deferredtax liability at the date of acquisition for taxable temporary differencesexisting at the purchase date in accordance with SFAS No. 109.  This amount was adjusted to $16.8 million in2006 as a result of the final purchase price adjustment for the Cincoacquisition.  See Notes 6 and 15.

(2)                Included in the development costs line itemare the asset retirement costs associated with the plugging and abandonmentliability related to SFAS No. 143 (see Note 7).

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

***Results of Operations -***Results of operations for the Company’s oil and natural gas producingactivities are summarized below:
| ** **                                                   | ** ** | **For the Year Ended December 31,** | ** ** |
|--------------------------------------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                                                   | ** ** | **2006**                                                     | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                   | ** ** | ***(in thousands)***                                    | ** ** |
| Oil and natural  gas revenue                                 |       | $                                                            | 129,744    |   | $ | 121,183 |   | $ | 64,505 |   |
| Operating  expenses:                                         |       |                                                         |       |   |   |   |   |
| Oil and natural gas operating expenses and ad  valorem taxes |       | 11,836                                                       |       | 10,102 |   | 5,356 |   |
| Production taxes                                             |       | 6,421                                                        |       | 6,966 |   | 3,953 |   |
| Accretion expense                                            |       | 189                                                          |       | 141 |   | 99 |   |
| Depletion expense                                            |       | 60,472                                                       |       | 39,810 |   | 21,472 |   |
| Income tax expense                                           |       | 17,721                                                       |       | 22,551 |   | 11,870 |   |
| Results of  operations from oil and gas producing activities |       | $                                                            | 33,105     |   | $ | 41,613 |   | $ | 21,755 |   |

 

F-36

----

 

***Reserves -***Provedreserves are estimated quantities of oil and natural gas, which geological andengineering data demonstrate with reasonable certainty to be recoverable infuture years from known reservoirs under existing economic and operating conditions.  Proved developed reserves are proved reservesthat can reasonably be expected to be recovered through existing wells withexisting equipment and operating methods. Proved oil and natural gas reserve quantities and the related discountedfuture net cash flows before income taxes (see Standardized Measure) for theperiods presented are based on estimates prepared by Ryder Scott Company andW.D. Von Gonten & Co., independent petroleum engineers.  Such estimates have been prepared inaccordance with guidelines established by the SEC.

The Company’s net ownership in estimated quantities ofproved oil and natural gas reserves and changes in net proved reserves, all ofwhich are located in the continental United States, are summarized below.
|                                                               | ** **   | **Natural Gas(Mcf)  For the Year Ended December 31,** | ** **   |
|---------------------------------------------------------------|--------------|-------------------------------------------------------------------------------------|--------------|
| ** **                                                    | ** **   | **2006**                                                                            | ** **   | **2005** | ** ** | **2004** | ** ** |
| ** **                                                    | *** *** | ***(in thousands)***                                                           | *** *** |
| Proved developed and undeveloped reserves |         |                                                                                |         |   |   |   |   |
| Beginning of year                                             |         | 82,290                                                                              |         | 66,311 |   | 46,824 |   |
| Revisions of previous estimates                               |         | (13,526                                                                             | )            | (7,737 | ) | (5,993 | ) |
| Purchase of oil and gas properties                            |         | 12,083                                                                              |         | 10,168 |   | 14,803 |   |
| Extensions and discoveries                                    |         | 9,202                                                                               |         | 26,145 |   | 19,825 |   |
| Sales of natural gas properties                               |         | (52                                                                                 | )            | — |   | — |   |
| Production                                                    |         | (13,850                                                                             | )            | (12,597 | ) | (9,148 | ) |
| End of year                                                   |         | 76,147                                                                              |         | 82,290 |   | 66,311 |   |
| Proved developed  reserves at year end                        |         | 60,163                                                                              |         | 59,066 |   | 50,698 |   |

 
|                                            | ** **   | **Oil, Condensate and Natural Gas Liquids(Bbls)  For the Year Ended December 31,** | ** ** |
|--------------------------------------------|--------------|--------------------------------------------------------------------------------------------------------------------------------------|------------|
| ** **                                 | ** **   | **2006**                                                                                                                             | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                 | *** *** | ***(in thousands)***                                                                                                            | ** ** |
| Proved developed  and undeveloped reserves |         |                                                                                                                                 |       |   |   |   |   |
| Beginning of year                          |         | 3,410                                                                                                                                |       | 3,792 |   | 2,851 |   |
| Revisions of previous estimates            |         | 675                                                                                                                                  |       | (640 | ) | (106 | ) |
| Purchase of oil and gas properties         |         | 322                                                                                                                                  |       | 114 |   | 268 |   |
| Extensions and discoveries                 |         | 502                                                                                                                                  |       | 775 |   | 1,270 |   |
| Sales of natural gas properties            |         | (17                                                                                                                                  | )          | — |   | — |   |
| Production                                 |         | (567                                                                                                                                 | )          | (631 | ) | (491 | ) |
| End of year                                |         | 4,325                                                                                                                                |       | 3,410 |   | 3,792 |   |
| Proved developed  reserves at year end     |         | 3,158                                                                                                                                |       | 2,852 |   | 2,698 |   |

 

***Standardized Measure -***The******Standardized Measure of DiscountedFuture Net Cash Flows relating to the Company’s ownership interests in provedoil and natural gas reserves for each of the three years ended December 31,2006 is shown below:
|                                                | ** ** | **For the Year Ended December 31,** | ** ** |
|------------------------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                                     | ** ** | **2006**                                                     | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                     | ** ** | ***(in thousands)***                                    | ** ** |
| Future cash  inflows                           |       | $                                                            | 616,605    |   | $ | 949,752 |   | $ | 521,263 |   |
| Future oil and natural  gas operating expenses |       | (131,926                                                     | )          | (192,550 | ) | (118,492 | ) |
|                                                |            |                                                              |            |  |  |  |  |  |  |  |

 

F-37

----

 
| Future  development costs                                 |   | (75,389  | )       | (79,651  | )      | (31,795 | )      |
|-----------------------------------------------------------|--------|----------|---------|----------|--------|---------|--------|
| Future income  tax expense                                |   | (65,738  | )       | (173,019 | )      | (75,095 | )      |
| Future net cash  flows                                    |   | 343,552  |    | 504,532  |   | 295,881 |   |
| 10% discount  factor                                      |   | (110,346 | )       | (160,742 | )      | (79,010 | )      |
| Standardized measure of  discounted future net cash flows |   | $        | 233,206 |     | $      | 343,790 |   | $ | 216,871 |   |
|                                                           |        |          |         |          |        |         |        |  |  |  |

 

In accordance with SEC regulations, the oil andnatural gas prices in effect at December 31, 2006, adjusted for basis andquality differentials, are applied to year-end quantities of proved oil andnatural gas reserves to compute future cash flows. The base prices beforeadjustments were $5.62 per MMbtu of natural gas, $36.64 per Bbl of natural gasliquids and $61.06 per Bbl of oil.

Future oil and natural gas operating expenses anddevelopment costs are computed primarily by the Company’s internal petroleumengineers and are provided to external independent petroleum engineers asestimates of expenditures to be incurred in developing and producing theCompany’s proved oil and natural gas reserves at the end of the year, based onyear-end costs and assuming the continuation of existing economic conditions.

Future income taxes are based on year-end statutoryrates, adjusted for net operating loss carryforwards and tax credits.  A discount factor of 10% was used to reflectthe timing of future net cash flows.  TheStandardized Measure of Discounted Future Net Cash Flows is not intended torepresent the replacement cost or fair market value of the Company’s oil andnatural gas properties.

The Standardized Measure of Discounted Future Net CashFlows does not purport, nor should it be interpreted, to present the fair valueof the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among otherthings, the recovery of reserves not presently classified as proved,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 -***Changesin Standardized Measure of Discounted Future Net Cash Flows relating to provedoil and gas reserves are summarized below:
| ** **                                                                   | ** **   | **For the Year Ended December 31,** | ** **   |
|------------------------------------------------------------------------------|--------------|--------------------------------------------------------------|--------------|
| ** **                                                                   | ** **   | **2006**                                                     | ** **   | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                   | *** *** | ***(in thousands)***                                    | *** *** |
| Changes due to  current year operations:                                     |         |                                                         |         |   |   |   |   |
| Sales of oil and natural gas, net of oil and natural  gas operating expenses |         | $                                                            | (101,520     | ) | $ | (105,638 | ) | $ | (56,969 | ) |
| Sales of oil and natural gas properties                                      |         | (618                                                         | )            | — |   | — |   |
| Purchase of oil and gas properties                                           |         | 34,855                                                       |         | 58,022 |   | 65,403 |   |
| Extensions and discoveries                                                   |         | 42,085                                                       |         | 119,850 |   | 65,467 |   |
| Changes due to  revisions of standardized variables:                         |         |                                                         |         |   |   |   |   |
| Prices and operating expenses                                                |         | (190,802                                                     | )            | 143,600 |   | 17,648 |   |
| Revisions of previous quantity estimates                                     |         | (29,018                                                      | )            | (54,208 | ) | (21,190 | ) |
| Estimated future development costs                                           |         | 44,992                                                       |         | 14,054 |   | (15,962 | ) |
| Income taxes                                                                 |         | 72,792                                                       |         | (74,281 | ) | (9,190 | ) |
| Accretion of discount                                                        |         | 34,379                                                       |         | 21,687 |   | 15,217 |   |
| Production rates (timing) and other                                          |         | (17,729                                                      | )            | 3,833 |   | 4,280 |   |
| Net change                                                                   |         | (110,584                                                     | )            | 126,919 |   | 64,704 |   |
| Beginning of  year                                                           |         | 343,790                                                      |         | 216,871 |   | 152,167 |   |
| End of year                                                                  |         | $                                                            | 233,206      |   | $ | 343,790 |   | $ | 216,871 |   |

 

Sales of oil and natural gas, net of oil and naturalgas operating expenses are based on historical pre-tax results.  Sales of oil and natural gas properties,extensions and discoveries, purchases of minerals in place and the changes 

F-38

----

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-39

----

 

# **INDEX TOEXHIBITS**

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-40

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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 (Incorporated by  reference from Exhibit 4.3 to the Company’s Annual Report on Form 10-K for  the year ended December 31, 2005 (File No. 000-22149)). |
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| 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)).                                                                                                                                                                                                                                                                                                                                                                         |
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| 4.8        |   | — |   | Fourth Amended and Restated Credit Agreement dated  January 31, 2007 by and among Edge Petroleum Corporation, as borrower, and  Union Bank of California, N.A., as Administrative Agent and Issuing Lender,  and the other lenders party thereto (Incorporated by reference from exhibit  4.1 to Edge’s Current Report on Form 8-K filed on February 5, 2007).                                                                                                                                                                                                                          |
|       |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| †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)).                                                                                                                                                                                                                                                                                                                                                                      |

 

F-41

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| †10.2   |   | — |   | Stock Option Plan of Edge Petroleum Corporation, a  Texas corporation (Incorporated by reference from exhibit 10.13 to the  Company’s Registration Statement on Form S-4 (Registration No. 333-17269)).                                                                                                                           |
|--------------|--------|--------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|         |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| †10.3   |   | — |   | Employment Agreement dated as of November 16, 1998,  by and between the Company and John W. Elias (Incorporated by reference from  10.12 to the Company’s Annual Report on Form 10-K for the year ended December  31, 1998).                                                                                                      |
|         |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| †10.4   |   | — |   | Amended and Restated Incentive Plan of Edge  Petroleum Corporation as Amended and Restated Effective as of August 1, 2006  (Incorporated by reference from exhibit 10.4 to the Company’s Quarterly  Report on Form 10-Q for the six months ended June 30, 2006).                                                                  |
|         |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| †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 Certain Other Compensation of Executive  Officers.                                                                                                                                                                                                                                                                        |
|         |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| †10.14  |   | — |   | Description of Annual Cash Bonus Program for  Executive Officers (Incorporated by reference from Exhibit 10.2 to the Company’s  Current Report on Form 8-K filed March 12, 2007.)                                                                                                                                            |
|         |   |   |   |                                                                                                                                                                                                                                                                                                                                   |
| †10.15  |   | — |   | New Base Salaries and Long-Term Incentive Awards for  Certain Executive Officers (Incorporated by reference from exhibit 10.1 to  the Company’s Current Report on Form 8-K filed August 25, 2006).                                                                                                                                |

 

F-42

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| 10.16  |   | — |   | Purchase and Sale Agreement between Smith  Production, Inc., as seller, and Edge Petroleum Exploration Company, as  purchaser, dated November 16, 2006 (Incorporated by reference to exhibit 10.1  to Edge’s Current Report on Form 8-K filed January 16, 2007).                                                                                  |
|--------|--------|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
| 10.17  |   | — |   | Purchase and Sale Agreement between Smith  Production, Inc., as seller, and Edge Petroleum Exploration Company, as  purchaser, dated November 16, 2006 (Incorporated by reference to exhibit 10.2  to Edge’s Current Report on Form 8-K filed January 16, 2007).                                                                                  |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
| 10.18  |   | — |   | First Amendment of Purchase and Sale Agreement  between Smith Production, Inc., as seller, and Edge Petroleum Exploration  Company, as purchaser, dated December 15, 2006 (Incorporated by reference to  exhibit 10.3 to Edge’s Current Report on Form 8-K filed January 16, 2007).                                                               |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
| 10.19  |   | — |   | Second Amendment of Purchase and Sale Agreement  between Smith Production, Inc., as seller, and Edge Petroleum Exploration  Company, as purchaser, dated January 15, 2007 (Incorporated by reference to  exhibit 10.1 to Edge’s Current Report on Form 8-K filed January 19, 2007).                                                               |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
| 10.20  |   | — |   | First Amendment of Purchase and Sale Agreement  between Smith Production, Inc., as seller, and Edge Petroleum Exploration  Company, as purchaser, dated January 15, 2007 (Incorporated by reference to  exhibit 10.2 to Edge’s Current Report on Form 8-K filed January 19, 2007).                                                                |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
| 10.21  |   | — |   | Third Amendment of Purchase and Sale Agreement  between Smith Production, Inc., as seller, and Edge Petroleum Exploration  Company, as purchaser, dated January 31, 2007 (Incorporated by reference to  exhibit 10.6 to Edge’s Current Report on Form 8-K filed February 7, 2007).                                                                |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
| 10.22  |   | — |   | Certificate of Designations establishing the 5.75%  Series A cumulative convertible perpetual preferred stock, dated January 27,  2007 (Incorporated by reference to exhibit 3.1 to Edge’s Current Report on  Form 8-K filed January 30, 2007).                                                                                                   |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
| 10.23  |   | — |   | Purchase and Sale Agreement between Kerr-McGee Oil  & Gas Onshore, L.P., as Seller, and Edge Petroleum Production Company, as  Purchaser, and Edge Petroleum Corporation, as Additional Purchaser dated  December 12, 2006 (Incorporated by reference from exhibit 2.1 to the  Company’s Current Report on Form 8-K filed December 18, 2006). |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
| *12.1  |   | — |   | Statement of Computation of Ratio of Earnings to  Fixed Charges.                                                                                                                                                                                                                                                                                       |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
| *21.1  |   | — |   | Subsidiaries of the Company.                                                                                                                                                                                                                                                                                                                           |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
| *23.1  |   | — |   | Consent of BDO Seidman, LLP.                                                                                                                                                                                                                                                                                                                           |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
| 23.2   |   | — |   | Consent of Ryder Scott Company (Incorporated by  reference from exhibit 23.1 to the Company’s Current Report on Form 8-K filed  January 23, 2007)                                                                                                                                                                                                 |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
| 23.3   |   | — |   | Consent of W.D. Von Gonten & Co. (Incorporated  by reference from exhibit 23.2 to the Company’s Current Report on Form 8-K  filed January 23, 2007)                                                                                                                                                                                           |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
| *23.4  |   | — |   | Consent of Ryder Scott Company.                                                                                                                                                                                                                                                                                                                        |
|   |   |   |   |                                                                                                                                                                                                                                                                                                                                                   |
| *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.                                                                                                                                                                                   |

 

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| *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, 2006 (Incorporated by reference from  exhibit 99.1 to the Company’s Current Report on Form 8-K filed January 23,  2007).        |
|       |   |   |   |                                                                                                                                                                                                                          |
| 99.2       |   | — |   | Summary of Reserve Report of W. D. Von Gonten &  Co. Petroleum Engineers as of December 31, 2006 (Incorporated by reference  from exhibit 99.2 to the Company’s Current Report on Form 8-K filed January  23, 2007). |
|       |   |   |   |                                                                                                                                                                                                                          |
| 99.3       |   | — |   | Oversight review letter of Ryder Scott Company  Petroleum Engineers dated January 11, 2007 (Incorporated by reference from  exhibit 99.2 to the Company’s Current Report on Form 8-K filed January 16,  2007).           |
|       |   |   |   |                                                                                                                                                                                                                          |
| *99.4      |   | — |   | Supplemental Summary of Reserve Report of Ryder  Scott Company Petroleum Engineers as of December 31, 2006.                                                                                                                   |

 

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* Filed herewith.

† Denotes management or compensatory contract,arrangement or agreement.

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