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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

FORM 10-K

|ý                                           |  | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934    
|------------------------------------------- |  | ----------------------------------------------------------------------------------------
|For the fiscal year ended December 31, 2007
|OR                                         
|o                                           |  | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from            to

Commission file number: 0-22149

EDGE PETROLEUM CORPORATION(Exact name of Registrant as specified in its charter)

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

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

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Securities
registered pursuant to Section 12(b) of the Act:

Title of each class

Name of each exchange on which registeredCommon Stock, Par Value $0.01 Per Share

NASDAQ5.75% Series A Cumulative Convertible Perpetual

NASDAQPreferred 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 a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. o Yes ý No

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. ý Yes o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter)
is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. ý

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

|Large accelerated filer o |  | Accelerated Filer ý |  | Non-accelerated filer o (Do not check if a smaller reporting company) |  | Smaller reporting company o
|------------------------- |  | ------------------- |  | --------------------------------------------------------------------- |  | ---------------------------

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

As of June 29, 2007, the aggregate market value of the voting stock held by non-affiliates of the registrant was $372.8 million (based on
a value of $14.01 per share, the closing price of the Common Stock as quoted by NASDAQ Global Select Market on such date).

As
of March 11, 2008, 28,569,491 shares of Common Stock, par value $.01 per share, were outstanding.

DOCUMENTS
INCORPORATED BY REFERENCE

Portions
of the definitive proxy statement for the registrant's 2008 Annual Meeting of Shareholders, to be filed pursuant to Regulation 14A under the Securities Exchange Act of
1934, are incorporated by reference into Part III of this report.



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TABLE OF CONTENTS



|               |  |                                                                                                              |  | Page
|-------------- |  | ------------------------------------------------------------------------------------------------------------ |  | ----
|               |  | PART I                                                                                                       |  |     
|ITEMS 1 AND 2. |  | BUSINESS AND PROPERTIES                                                                                      |  | 4   
|ITEM 1A.       |  | RISK FACTORS                                                                                                 |  | 24  
|ITEM 1B.       |  | UNRESOLVED STAFF COMMENTS                                                                                    |  | 31  
|ITEM 3.        |  | LEGAL PROCEEDINGS                                                                                            |  | 34  
|ITEM 4.        |  | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS                                                          |  | 37  
|               |  | PART II                                                                                                      |  |     
|ITEM 5.        |  | MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |  | 39  
|ITEM 6.        |  | SELECTED FINANCIAL DATA                                                                                      |  | 41  
|ITEM 7.        |  | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION                         |  | 43  
|ITEM 7A.       |  | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                                                   |  | 72  
|ITEM 8.        |  | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA                                                                  |  | 73  
|ITEM 9.        |  | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES                        |  | 73  
|ITEM 9A.       |  | CONTROLS AND PROCEDURES                                                                                      |  | 73  
|ITEM 9B.       |  | OTHER INFORMATION                                                                                            |  | 75  
|               |  | PART III                                                                                                     |  |     
|ITEM 10.       |  | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE                                                       |  | 76  
|ITEM 11.       |  | EXECUTIVE COMPENSATION                                                                                       |  | 76  
|ITEM 12.       |  | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS               |  | 76  
|ITEM 13.       |  | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE                                    |  | 76  
|ITEM 14.       |  | PRINCIPAL ACCOUNTANT FEES AND SERVICES                                                                       |  | 76  
|               |  | PART IV                                                                                                      |  |     
|ITEM 15.       |  | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES                                                                   |  | 77  

2

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EDGE PETROLEUM CORPORATION

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

FORWARD LOOKING INFORMATION

Certain of the statements contained in all parts of this Annual Report on Form 10-K including, but not limited to, those relating to our
drilling plans (including scheduled and budgeted wells), the effect of changes in strategy and business discipline, future tax matters, our 3-D project portfolio, future general and
administrative expenses on a per unit of production basis, changes in wells operated and reserves, future growth and expansion, future exploration, future seismic data (including timing and results),
the ongoing assessment of strategic alternatives, expansion of operation, our ability to generate additional prospects, review of outside generated prospects and acquisitions, additional reserves and
reserve increases, replace production and manage our asset base, enhancement of visualization and interpretation strengths, expansion and improvement of capabilities, integration of new technology
into operations, credit facilities, redetermination of our borrowing base, attraction of new members to the technical team, future compensation programs, new focus on core areas, new prospects and
drilling locations, new alliances, future capital expenditures (or funding thereof) and working capital, sufficiency of future working capital, borrowings and capital resources and liquidity,
projected rates of return, retained earnings and dividend policies, projected cash flows from operations, future commodity price environment, expectation or timing of reaching payout, outcome, effects
or timing of any legal proceedings or contingencies, the impact of any change in accounting policies on our financial statements, the number, timing or results of any wells, the plans for timing,
interpretation and results of new or existing seismic surveys or seismic data, future production or reserves, future acquisition of leases, lease options or other land rights, any other statements
regarding future operations, financial results, opportunities, growth, business plans and strategy and other statements that are not historical facts are forward-looking statements. These
forward-looking statements reflect our current view of future events and financial performance. When used in this document, the words "budgeted," "anticipate," "estimate," "expect," "may," "project,"
"believe," "intend," "plan," "potential," "forecast," "might," "predict," "should" and similar expressions are intended to be among the expressions that identify forward-looking statements. These
forward-looking statements speak only as of their dates and should not be unduly relied upon. We undertake no obligation to publicly update or revise any forward-looking
statement, whether as a result of new information, future events, or otherwise. Such statements involve risks and uncertainties, including, but not limited to, those set forth under ITEM 1A. "RISK FACTORS,"the ongoing assessment of strategic alternatives and other factors detailed in this document and our other filings with the
Securities and Exchange Commission. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those
indicated. All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by reference to these risks and
uncertainties.

AVAILABLE INFORMATION

Our website address iswww.edgepet.com. We make our website content available for information purposes only. It
should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. We make available on this website under "Investor RelationsSEC
Filings," free of charge, 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 as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities and Exchange Commission ("SEC"). The SEC also maintains a
website atwww.sec.govthat contains reports, proxy statements and other information regarding SEC registrants, including us.

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PART I

ITEMS 1 AND 2.    BUSINESS AND PROPERTIES

Overview & History

Edge Petroleum Corporation is an independent oil and natural gas company engaged in the exploration, development, acquisition and production of crude oil and
natural gas properties from select onshore basins in the United States. Edge was founded in 1983 as a private company and went public in 1997. We have evolved over time from a prospect generation
organization focused on high-risk, high-reward exploration projects to a team-driven organization focused on a balanced program of exploration, exploitation,
development and acquisition of oil and natural gas properties.

Recent Developments

At year-end 2007, our net proved reserves were 163.5 Bcfe, comprised of 116.6 billion cubic feet of natural gas, 4.8 million barrels of
natural gas liquids and 3.0 million barrels of crude oil and condensate. Natural gas and natural gas liquids accounted for approximately 89% of those proved reserves. Approximately 77% of total
proved reserves were developed as of year-end 2007 and they were all located onshore, in the United States. Our 2007 drilling program produced 46 apparent successes out of 50 wells
drilled. We also continued developing and exploiting assets in south
Texas, our largest core area, and began development of our Shale Plays. During 2007, we focused a great deal of our efforts on integrating the assets acquired in January 2007 from a privately held
company (see below).

January 2007 AcquisitionOn January 31, 2007, we completed the purchase of certain oil and natural gas properties
located in 13 counties in south and southeast Texas and other associated assets from a privately held company ("January 2007 Acquisition"). We paid approximately $384.4 million for these
assets. This was our largest acquisition to date, and we spent much of 2007 integrating these assets into our business. In January 2007, we also completed concurrent public offerings of 10,925,000
shares of our common stock for net proceeds of approximately $138.1 million and 2,875,000 shares of our 5.75% Series A cumulative convertible perpetual preferred stock for net proceeds
of approximately $138.4 million. We used the net proceeds from these offerings, along with borrowings under our current credit facility, to finance the January 2007 Acquisition and to repay our
prior credit facility.

Strategic Assessment ProcessOn December 18, 2007, we announced the hiring of a financial advisor to assist our Board
of Directors with an assessment of strategic alternatives. On February 7, 2008, we provided an update on the strategic assessment process, which included a thorough review and assessment of our
strengths and weaknesses, competitive position and asset base, reporting that after careful analysis, management and our Board of Directors believed that the best route to maximizing stockholder value
at that time was to focus on an assessment of a potential merger or sale of Edge. We are working diligently to explore this alternative. A decision on any particular course of action has not been made
and there can be no assurance that our Board of Directors will authorize any transaction. While that process is continuing, we intend to operate Edge in a manner designed to capture the most value
possible for our stockholders.

During
the first quarter of 2008, we expect to complete the sale of a small group of non-core assets, which will have an effective date of March 1, 2008. We intend to
use the sale proceeds to pay down a portion of our outstanding borrowings under our credit facility.

Strategy

Given the backdrop of the ongoing strategic assessment process, we will be operating with a reduced capital spending program as we enter 2008 and while we
continue to assess the potential sale or merger of the Company. This interim program, which could be supplemented quickly, calls for the

4

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drilling
of 18 to 22 wells (7 to 9, net) during 2008, primarily in south Texas, and to a lesser extent in southeast New Mexico, complemented by selected expenditures for land and seismic. The interim
program is estimated to have total capital spending in the range of $50 to $60 million.

In
the past, our business strategy has been based on the following six main elements:

1.Grow reserves through acquisitions and the drilling of a balanced portfolio of prospects.We seek to maintain
a prudent balance between higher risk/reward wells and more moderate risk/reward wells. In 2007, we drilled 50 wells (27.32 net), primarily in Texas, with 46 (24.54 net) of those wells completed as
productive for an apparent success rate of approximately 92%. Our drilling and acquisition program helped us to replace 362% of our 2007 production (see "Oil and Natural Gas Reserve Replacement").
Over the last three years, we drilled 167 wells (91.70 net). Of the drilled wells, 151 gross (81.13 net) have been completed as apparent successes, for a success rate of approximately 90%. As a result
of our acquisitions and drilling program, we have grown production and proved reserves since December 31, 2004. Production has grown from 12.1 Bcfe for the year ended December 31, 2004
to 24.1 Bcfe for the year ended December 31, 2007, an increase of approximately 99%. Also, we have grown proved reserves from approximately 89.1 Bcfe at year-end 2004 to 163.5 Bcfe
at December 31, 2007.

2.Seek acquisitions that we believe have upside potential.We seek acquisitions of producing properties that
typically have exploration or exploitation upside potential. As illustrated by the January 2007 Acquisition, we primarily seek properties in our existing core areas or as a means to establish new core
areas. We do not plan on pursuing any significant acquisitions during our strategic assessment process.

3.Focus on specific geographic areas where we believe we can add value.We believe geographic focus is a
critical element of success. Long-term success requires detailed knowledge of both geologic and geophysical attributes, as well as operating conditions in the areas in which we operate. As
a result, we focus on a select number of geographic areas where our experience and strengths can be applied with a significant influence on the outcome.

4.Integrate technological advances into our exploration, drilling, production operations and administration.We use advanced technologies as risk-reduction tools in our exploration, development, drilling and completion activities. Data analysis and advanced processing techniques,
combined with our more traditional sub-surface interpretation techniques, allow our team of technical personnel to more easily identify features, structural details and fluid contacts that
could be overlooked using less sophisticated data interpretation techniques.

5.Maintain a conservative financial structure and control our cost structure.We believe that a conservative
financial structure is crucial to consistent, positive financial results, management of cyclical swings in our industry and the ability to move quickly to take advantage of acquisitions and attractive
drilling opportunities. In order to maximize our financial flexibility, we try to maintain a target range of 30% to 40% for our debt-to-total capital ratio. At
December 31, 2007, our debt-to-total capital ratio was 37.4%.



6.Use equity ownership and performance based compensation programs to attract and retain a high-quality
workforce.In late 1998, we eliminated the previous overriding royalty compensation system and replaced it with a system designed to reward all employees through
performance-based compensation that is competitive with our peers and through equity ownership. As of March 11, 2008,

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our
directors and employees, including executive officers, owned or had options to acquire an aggregate of approximately 7% of our outstanding common stock.

Employees

As of March 11, 2008, we had 86 full-time employees. We believe that our relationships with our employees are good. None of our employees are
covered by a collective-bargaining agreement. From time to time, we utilize the services of independent consultants and contractors to perform various professional services, particularly in the areas
of construction, design, well-site surveillance, permitting and environmental assessment. Field and on-site production operation services, such as pumping, maintenance,
dispatching, inspection and testing are generally provided by independent contractors.

Offices

We lease executive and corporate office space located at 1301 Travis Street in downtown Houston, Texas.

Oil and Natural Gas Reserves

The following table sets forth our estimated net proved oil and natural gas reserves and the present value of estimated future net cash flows related to such
reserves as of December 31, 2007. Our reserves increased significantly in 2007 primarily due to the January 2007 Acquisition. Increases in reserves from extensions and discoveries in 2007 were
primarily the result of the drilling of 46 productive wells, 87%
of which were development and 13% of which were exploratory. Revisions of previous estimates during 2007 were primarily due to (1) the drilling of two proved undeveloped ("PUD") locations that
were dry holes, one in southeast Texas and one in south Texas (2) writing down 13 PUD location reserves primarily based on poor offset well performance, (3) poor response on
recompletions in south Texas that affected proved behind pipe reserves and (4) updated performance (both positive and negative) on existing wells.

We
engaged Ryder Scott Company, L.P. ("Ryder Scott") and W. D. Von Gonten & Co. ("WDVG") to estimate our net proved reserves, projected future production, estimated
future net revenue attributable to our proved reserves, and the present value of such estimated future net revenue as of December 31, 2007. Ryder Scott and WDVG's estimates were 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 past 14 years and WDVG
has independently evaluated the reserves we acquired from Contango Oil and Gas Company late in 2004 for the past six years. In estimating the reserve quantities that are economically recoverable,
Ryder Scott and WDVG used oil and natural gas prices in effect at December 31, 2007 and estimated development and production costs that were in effect during December 2007 without giving effect
to hedging activities. In accordance with SEC regulations, no price or cost escalation or reduction was considered by Ryder Scott and WDVG. For further information concerning Ryder Scott and WDVG's
estimates of our proved reserves at December 31, 2007, see the summaries of the reserve reports of Ryder Scott and WDVG included as exhibits to this Form 10-K (respectively,
the "Ryder Scott Report" and the "WDVG Report"). In accordance with Statement of Financial Accounting Standards ("SFAS") No. 69,Disclosures About Oil and Natural Gas
Producing Activities,the present value of estimated future net revenues after income taxes was prepared using constant prices as of the calculation date, discounted at 10% per
annum, and is not intended to represent the current market value of the estimated oil and natural gas reserves we owned. For further information concerning the present value of future net revenue from
these proved reserves, see Note 22 to our consolidated financial statements. See alsoITEM 1A. "RISK FACTORS."

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The
oil and natural gas reserve data included in or incorporated by reference in this document are only estimates and may prove to be inaccurate.

|                                                                                                |             | Proved Reserves as of December 31, 2007 |        
|----------------------------------------------------------------------------------------------- | ----------- | --------------------------------------- | -------
|
|Oil and condensate (MBbls)                                                                      |             |                                         | 2,580  
|Natural gas liquids (MBbls)                                                                     |             |                                         | 3,732  
|Natural gas (MMcf)                                                                              |             |                                         | 88,134 
|                                                                                                | Total MMcfe |                                         |        
|In thousands:                                                                                   |             |                                         |        
|Estimated future net revenue before income taxes                                                |             | $                                       | 751,748
|Present value of estimated future net revenue before income taxes (discounted 10% per annum)(3) |             | $                                       | 522,104
|Future income taxes (discounted 10% per annum)                                                  |             |                                         | (37,500
|                                                                                                |             |                                         |        
|Standardized measure of discounted future net cash flows                                        |             | $                                       | 484,604
|                                                                                                |             |                                         |        

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The
reserve data set forth herein represents estimates only. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be
measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result,
estimates made by different

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engineers
often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates, and such revisions may be
material. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Furthermore, the estimated future net revenue from proved
reserves and the present value thereof are based upon certain assumptions, including current prices, production levels and costs that may not be what is actually incurred or realized. No estimates of
proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.

In
accordance with SEC regulations, the Ryder Scott Report and the WDVG Report each used year-end oil and natural gas prices in effect at December 31, 2007, adjusted
for basis and quality differentials. The prices used in calculating the estimated future net revenue attributable to proved reserves do not necessarily reflect market prices for oil and natural gas
production subsequent to December 31, 2007. There can be no assurance that all of the proved reserves will be produced and sold within the periods indicated, that the assumed prices will
actually be realized for such production or that existing contracts will be honored or judicially enforced. Decreases in the assumed commodity prices result in decreases in estimated future net
revenue as well as in estimated reserves.

Oil and Natural Gas Reserve Replacement

Finding and developing sufficient amounts of natural gas and crude oil reserves at economical costs are critical to our long-term success. Our
business, as with other extractive businesses, is a depleting one in which each gas equivalent unit produced must be replaced or our asset base and ability to generate revenues in the future will
shrink. Given the inherent decline of reserves resulting from the production of those reserves, it is important for an exploration and production company to demonstrate a long-term trend
of more than offsetting produced volumes with new reserves that will provide for future production. We use the reserve replacement ratio, as defined below, as an indicator of our ability to replenish
annual production volumes and grow our reserves, thereby providing some information on the sources of future production and income. We believe that reserve replacement is relevant and useful
information that is commonly used by analysts, investors and other interested parties in the oil and gas industry as a means of evaluating the operational performance and to a greater extent the
prospects of entities engaged in the production and sale of depleting natural resources. These measures are often used as a metric to evaluate an entity's historical track record of replacing the
reserves that it produced. The reserve replacement ratio is calculated by dividing the sum of reserve additions from all sources (revisions, acquisitions, extensions and discoveries) by the actual
production for the corresponding period. Additions to our reserves are proven developed and proven undeveloped reserves. We expect to continue adding to our reserve base through these activities, but
certain factors outside our control may impede our ability to do so (seeITEM 1A. "RISK FACTORS"). The values for these reserve additions and production
are derived directly from the proved reserves table in Note 22 to our consolidated financial statements. Accordingly, we do not use unproved reserve quantities. The reserve replacement ratio is
a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions.
Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not consider the cost or timing of future production of new reserves, it cannot be used as
a measure of value creation. The ratio does not distinguish between changes in reserve quantities that are developed and those that will require additional time and funding to develop. In that regard,
the percentage of reserves that were developed was 77%, 77%, and 74% for

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the
years ended December 31, 2007, 2006 and 2005, respectively. Set forth below is our reserve replacement ratio for the periods indicated.

|                          |  | For the Year Ended
December 31, |   |    |  
|------------------------- |  | ------------------------------- | - | -- | -
|
|
|Reserve Replacement Ratio |  | 362                             | % | 97 | %

Oil and Natural Gas Volumes, Prices and Operating Expense

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

|                                                               |                                     | Year Ended December 31,
|-------------------------------------------------------------- | ----------------------------------- | -----------------------
|
|Production:                                                    |                                     |                        
|                                                               | Oil and condensate (MBbls)          |                        
|                                                               | Natural gas liquids (MBbls)         |                        
|                                                               | Natural gas (MMcf)                  |                        
|                                                               | Natural gas equivalent (MMcfe)      |                        
|Average sales pricebefore hedging and derivatives:            |                                     |                        
|                                                               | Oil and condensate ($ per Bbl)      |                        
|                                                               | Natural gas liquids ($ per Bbl)     |                        
|                                                               | Natural gas ($ per Mcf)             |                        
|                                                               | Natural gas equivalent ($ per Mcfe) |                        
|Average sales priceafter hedging and derivatives:             |                                     |                        
|                                                               | Oil and condensate ($ per Bbl)      |                        
|                                                               | Natural gas liquids ($ per Bbl)     |                        
|                                                               | Natural gas ($ per Mcf)             |                        
|                                                               | Natural gas equivalent ($ per Mcfe) |                        
|Average oil and natural gas operating expenses ($ per Mcfe)(1) |                                     | $                      
|Average production and ad valorem taxes ($ per Mcfe)           |                                     | $                      

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Exploration, Development and Acquisition Capital Expenditures

The following table sets forth certain information regarding the total costs incurred in connection with exploration, development and acquisition activities.

Year Ended December 31,2007

2006

2005(in thousands)Acquisition costs:Unproved properties

$
64,483

$
21,661

$
33,948Proved properties(1)


336,022


36,573


66,472Exploration costs


41,240


17,898


20,426Development costs


71,954


64,724


58,685Subtotal


513,699


140,856


179,531Asset retirement costs


2,966


416


436Total costs incurred

$
516,665

$
141,272

$
179,967




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

Drilling Activity

The following table sets forth our drilling activity for the periods indicated. In the table, "Gross" refers to the total wells in which we have a working
interest or back-in working interest after payout and "Net" refers to gross wells multiplied by our working interest therein.

|              |                | Year Ended December 31, |   
|------------- | -------------- | ----------------------- | --
|
|
|Exploratory:  |                |                         |   
|              | Productive     |                         | 6 
|              | Non-productive |                         | 2 
|              |                |                         |   
|              |                | Total                   |   
|              |                |                         |   
|Development:  |                |                         |   
|              | Productive     |                         | 40
|              | Non-productive |                         | 2 
|              |                |                         |   
|              |                | Total                   |   
|              |                |                         |   
|Grand Total   |                | 50                      |   
|              |                |                         |   
|Success Ratio |                | 92                      | % 
|              |                |                         |   

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Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2007.

|            |       | Company-Operated |     | Non-Operated |        | Total
|----------- | ----- | ---------------- | --- | ------------ | ------ | -----
|
|Oil         |       | 51               |     | 37.44        |        | 78   
|Natural gas |       | 251              |     | 180.47       |        | 242  
|            |       |                  |     |              |        |      
|            | Total |                  | 302 |              | 217.91 |      
|            |       |                  |     |              |        |      

Acreage Data

The following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31, 2007. Developed acres refer to
acreage within producing units and undeveloped acres refer to acreage that has not been placed in producing units.

|                                  |       | Developed Acres |         | Undeveloped Acres |        | Total 
|--------------------------------- | ----- | --------------- | ------- | ----------------- | ------ | ------
|
|TexasVicksburg                   |       | 14,881          |         | 7,764             |        | 53,825
|TexasQueen City                  |       | 14,924          |         | 9,118             |        |      
|TexasDeep Frio                   |       | 3,910           |         | 3,743             |        | 6,497 
|TexasOther                       |       | 47,190          |         | 17,694            |        | 10,068
|Mississippi Interior Salt Basin   |       | 7,872           |         | 3,851             |        | 17,834
|Southeast New Mexico              |       | 7,571           |         | 2,436             |        | 93,141
|South Louisiana                   |       | 1,906           |         | 470               |        | 105   
|Arkansas (Fayetteville Shale)     |       | 1,363           |         | 1,152             |        | 4,298 
|Alabama                           |       | 750             |         | 46                |        |      
|Michigan                          |       | 160             |         | 160               |        | 498   
|Mississippi/Alabama (Floyd Shale) |       |                |         |                  |        | 44,732
|Montana                           |       |                |         |                  |        | 1,198 
|                                  |       |                 |         |                   |        |       
|                                  | Total |                 | 100,527 |                   | 46,434 |       
|                                  |       |                 |         |                   |        |       

Leases
covering approximately 41,530 gross (25,404 net), 38,449 gross (15,606 net) and 34,740 gross (26,145 net) undeveloped acres are scheduled to expire in 2008, 2009 and 2010,
respectively. In general, our leases will continue past their primary terms if oil and natural gas production in commercial quantities is being produced from a well on such lease or other drilling or
reworking operations are being continuously prosecuted.

The
table above does not include 37,487 gross (35,833 net) undeveloped acres in Texas for which we have the option to acquire leases based upon a commitment of continuous drilling. We
estimate that these options to acquire leased acreage will expire in 2008, based on our current well and 3-D seismic acquisition schedule.

Core Areas of Operation

As of December 31, 2007, 85% of our proved reserves were in Texas, 6% in Mississippi, 5% in New Mexico, and 4% in south Louisiana, Michigan, Alabama and
Arkansas. In south Texas, our

11

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exploration
and production activities are concentrated in three primary plays: Vicksburg, Queen City and Deep Frio trends. Our principal properties are located in the following areas of the United
States:

GRAPHIC

The
table below sets forth the gross and net number of our gas, oil and service wells in each of our core areas of operation as of December 31, 2007. Net wells are calculated
based on our working or net revenue interest in each of the properties we own.

|                                |  | Gas Wells |  | Oil Wells |  | Service Wells(1)
|------------------------------- |  | --------- |  | --------- |  | ----------------
|
|TexasVicksburg                 |  | 159       |  | 60.10     |  | 4               
|TexasQueen City                |  | 90        |  | 60.11     |  | 1               
|TexasDeep Frio                 |  | 42        |  | 39.77     |  | 6               
|TexasOther                     |  | 167       |  | 89.96     |  | 52              
|South Louisiana                 |  | 6         |  | 1.38      |  |                
|Mississippi Interior Salt Basin |  | 9         |  | 5.44      |  | 29              
|Alabama                         |  |          |  |          |  | 5               
|Arkansas                        |  | 3         |  | 1.18      |  |                
|Michigan                        |  | 1         |  | 1.00      |  |                
|Southeast New Mexico            |  | 16        |  | 5.88      |  | 32              
|                                |  |           |  |           |  |                 
|Total                           |  | 493       |  | 264.82    |  | 129             
|                                |  |           |  |           |  |                 

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12

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We
conduct our operations primarily along the onshore United States Gulf Coast, with our primary emphasis in south Texas, Mississippi, Arkansas, Louisiana and southeast New Mexico. Our
resources and assets are managed and our results reported as one operating segment. The following table sets out a brief comparative summary of certain key 2007 data for each area.

|                                |                  | Production MMcfe |       | Percentage of Total Production |     | Production Revenue
(In thousands) |         | Estimated Proved Reserves MMcfe |         | Percentage of Total Estimated Proved Reserves |         | Gross New Wells Drilled |      | Gross New Productive Wells Drilled
|------------------------------- | ---------------- | ---------------- | ----- | ------------------------------ | --- | --------------------------------- | ------- | ------------------------------- | ------- | --------------------------------------------- | ------- | ----------------------- | ---- | ----------------------------------
|State / Trend:                  |                  |                  |       |                                |     |                                   |         |                                 |         |                                               |         |                         |      |                                   
|                                | TexasVicksburg  |                  | 6,587 |                                | 28% |                                   | $       | 47,435                          |         | 64,391                                        |         | 39%                     |      | 20                                
|                                | TexasQueen City |                  | 5,023 |                                | 21% |                                   |         | 36,304                          |         | 17,918                                        |         | 11%                     |      | 4                                 
|                                | TexasDeep Frio  |                  | 2,765 |                                | 11% |                                   |         | 20,431                          |         | 21,177                                        |         | 13%                     |      | 5                                 
|                                | TexasOther      |                  | 6,680 |                                | 28% |                                   |         | 45,697                          |         | 36,158                                        |         | 22%                     |      | 2                                 
|                                |                  |                  |       |                                |     |                                   |         |                                 |         |                                               |         |                         |      |                                   
|Total Texas                     |                  | 21,055           |       | 88%                            |     |                                   | 149,867 |                                 | 139,644 |                                               | 85%     |                         | 31   |                                   
|Mississippi Interior Salt Basin |                  | 1,032            |       | 4%                             |     |                                   | 8,904   |                                 | 9,071   |                                               | 6%      |                         | 1    |                                   
|Arkansas                        |                  | 105              |       | *                              |     |                                   | 533     |                                 | 485     |                                               | *       |                         | 7    |                                   
|South Louisiana                 |                  | 148              |       | 1%                             |     |                                   | 1,425   |                                 | 6,616   |                                               | 4%      |                         |     |                                   
|Southeast New Mexico            |                  | 1,671            |       | 7%                             |     |                                   | 12,838  |                                 | 7,382   |                                               | 5%      |                         | 11   |                                   
|Michigan                        |                  | 100              |       | *                              |     |                                   | 751     |                                 | 244     |                                               | *       |                         |     |                                   
|All Others                      |                  | 7                |       | *                              |     |                                   | 520     |                                 | 30      |                                               | *       |                         |     |                                   
|                                |                  |                  |       |                                |     |                                   |         |                                 |         |                                               |         |                         |      |                                   
|                                |                  | Company Total    |       | 24,118                         |     | 100%                              |         | $                               | 174,838 |                                               | 163,472 |                         | 100% |                                   
|                                |                  |                  |       |                                |     |                                   |         |                                 |         |                                               |         |                         |      |                                   

---

South & southeast Texas

As of December 31, 2007, we owned an interest in 151,295 gross (59,483 net) acres in Texas. Our areas of focus in this region are predominantly in the
Vicksburg, Queen City and Deep Frio producing trends. As of December 31, 2007, we operated approximately 263 wells, which along with our 258 non-operated wells accounted for about
87% of our total net production in 2007. We drilled 31 wells during 2007 in Texas, 94% of which were apparent successes. The majority of our 2007 drilling activity took place in the Vicksburg project
area. We drilled 20 apparently successful wells in the Vicksburg project area, five in the Deep Frio project area and four in the Queen City project area. In 2008, we currently expect to drill 14
gross wells (6 net) in our core areas in Texas. The majority of these wells are planned in the Vicksburg project area.

South Louisiana

As of December 31, 2007, we owned an interest in 2,011 gross (575 net) acres in south Louisiana primarily located in Acadia, Calcasieu, Lafayette,
St. Landry and Vermilion Parishes. As of December 31, 2007, we had an interest in 6 wells, none of which we operate. We did not drill any wells in south Louisiana in 2007 and we have no
current plans to drill additional wells in this area in 2008.

Mississippi Interior Salt Basin

As of December 31, 2007, we owned an interest in 25,706 gross (13,563 net) acres in the Mississippi Interior Salt Basin area and 44,732 gross (38,340 net)
undeveloped acreage in the Floyd Shale play. We acquired reserves and production in the Mississippi Interior Salt Basin in south central Mississippi as part of the 2003 merger with Miller Exploration
Company ("Miller"). The primary

13

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producing
horizons in the Mississippi Interior Salt Basin around the Miller properties include the Hosston, Sligo, Rodessa and James Lime sections. As of December 31, 2007, we operated eleven
wells in this area. Production from wells in the Mississippi Interior Salt Basin accounted for approximately 4% of our total net production in 2007. In 2007, we drilled one well (1.0 net) in this
area. We have no plans to drill additional wells in Mississippi at this time.

Michigan

As of December 31, 2007, we owned an interest in 658 gross (658 net) acres in Michigan. We acquired acreage and one producing well in south central
Michigan as part of the 2003 merger with Miller. We operate this well which produces from the Trenton/Black River formation at approximately 3,000 feet and this well accounted for less than 1% of our
total net production in 2007. We have no plans for additional activity in Michigan in 2008 at this time.

Southeast New Mexico

As of December 31, 2007, we owned an interest in 100,712 gross (20,942 net) acres in this area that we earned through a drilling obligation we fulfilled
during 2004 and 2005 and through subsequent purchases. The objectives in this area are shallow oil in the Yeso, San Andres, Queen and Grayburg formations, and deep natural gas in the Atoka and Morrow
formations. Additional objectives are the Strawn, Cisco, Wolfcamp and Devonian formations. In 2007, we participated in the drilling of 11 gross (4.7 net) wells, of which 100% were apparent successes.
Production from wells in the southeast New Mexico area represented approximately 7% of our total net production in 2007. During 2008, we anticipate drilling 6 wells (2 net) in southeast New Mexico.

Arkansas

As of December 31, 2007, we owned an interest in 5,661 gross (4,692 net) undeveloped acres in the Fayetteville Shale play in south central Arkansas. In
2007, we drilled seven wells (3.8 net), six (3.2 net) of which were apparent successes. Five wells in Arkansas had operations temporarily suspended at year-end 2007 because fracture
stimulation during the completion of our initial wells caused communication with an underlying water bearing zone. Many of the planned 2007 wells have been deferred and some of the reserves that we
originally expected to be classified as proved were moved to the non-proved category. Production from wells in the Arkansas area represented less than 1% of our total net production in
2007. Due to the ongoing strategic assessment process, we do not anticipate additional drilling in this area during 2008.

Title to Properties

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

We
have granted mortgage liens on substantially all of our oil and natural gas properties in favor of Union Bank of California, as agent, to secure our credit facility. These mortgages
and the credit facility contain substantial restrictions and operating covenants that are customarily found in loan agreements of this type. SeeITEM 7. "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF

14

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FINANCIAL CONDITION AND RESULTS OF OPERATIONSLIQUIDITY AND CAPITAL RESOURCESCREDIT FACILITY"and
Note 10 to our consolidated financial statements.

Marketing

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

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

There
are 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 transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulations on oil and natural gas
production and sales. We have not experienced any significant difficulties in marketing our oil and natural gas. The oil and natural gas industry also competes with other industries in supplying the
energy and fuel requirements of industrial, commercial and individual customers. Where feasible, we use a combination of market-sensitive pricing and forward-fixed pricing. Forward pricing is utilized
to take advantage of anomalies in the futures market.

Delivery Commitments

During 2007, we executed a gas gathering and compression services agreement with Frontier Midstream, LLC ("Frontier"). Following execution of such
agreement, Frontier expedited the installation of the Rose Bud system in White County, Arkansas, including the high and low pressure gathering lines, dehydration, compression and the interconnect with
Ozark, in order to accommodate our desire to be able to deliver natural gas as soon as our wells were completed. At the time of signing the contract, we had completed and tested two productive wells
in the Moorefield shale in Arkansas. The Rose Bud system was installed, operational and ready to deliver our production in June 2007. The contract minimum commitment to Frontier is 2.7 Bcf over a
three year period for the pipeline interconnect. This line carries a $0.29 per Mcf deficiency rate, for a total commitment for the pipeline of approximately $0.8 million. We have delivered
approximately $41,400 of this commitment through December 31, 2007. In addition to the pipeline, Frontier also built and installed lateral gathering lines to eight locations. The remaining
commitment on these laterals is $1,305,000, for a total potential liability of approximately $2.0 million to be paid by June 2010 if the minimum volumes are not delivered. We currently have not
recorded a liability for these commitments as we expect to meet the minimum physical delivery based on estimated production.

This
contract is not considered a derivative, but has been designated as an annual sales contract under Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging
Activities(as amended).

Derivatives

Due to the instability of oil and natural gas prices, we may enter into, from time to time, price risk management transactions (e.g., swaps, collars and
floors) on our expected oil and natural gas production to seek to achieve a more predictable cash flow, as well as to reduce exposure to price

15

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fluctuations.
While the use of these arrangements may limit our ability to benefit from increases in the price of oil and natural gas, it is also intended to reduce our potential exposure to adverse
price movements. SeeITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSAPPROACH TO THE
BUSINESS" for a discussion of our current level of derivative contracts as it relates to expected production. Our price-risk management arrangements, to the extent we enter into any, are
intended to apply to only a portion of our expected production, and thereby provide only partial price protection against declines in oil and natural gas prices while limiting our potential gains from
future increases in prices. None of these instruments are, at the time of their execution, intended to be used for trading purposes, but may be deemed as such due to the expected decrease in our
anticipated 2008 production. All such derivative transactions provide for financial rather than physical settlement. These derivative transactions are generally placed with major financial
institutions that the Company believes are minimal credit risks. On a quarterly basis, our management reviews all of our price-risk management transaction policies, including volumes,
accounting treatment, types of instruments and counterparties. These policies are implemented by management through the execution of trades by the Chief Financial Officer after consultation with and
concurrence by the President and Chairman of the Board. Our Board of Directors monitors our price-risk management policies and trades on a monthly basis. We account for these transactions
as hedging and derivative activities and, accordingly, certain gains and losses are included in revenue during the period the transactions occur (see Note 9 to our consolidated financial
statements andITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSCRITICAL ACCOUNTING POLICIES
AND ESTIMATESDERIVATIVES AND HEDGING ACTIVITIES.").

All
of our price-risk management transactions are considered derivative instruments and are accounted for in accordance with SFAS No. 133. These derivative instruments
are intended to hedge our price-risk and may be considered hedges for economic purposes, but certain of these transactions may not qualify for cash flow hedge accounting. All derivative
instruments, other than those that meet the normal purchases and sales exception, are recorded on the balance sheet at fair value and the cash flows resulting from settlement of these derivative
transactions are classified in operating activities on the statement of cash flows. For those derivatives to which mark-to-market accounting treatment is applied, the changes
in fair value are not deferred through other comprehensive income on the balance sheet. Rather they are immediately recorded in total revenue on the statement of operations. For those derivatives that
are designated and qualify for cash flow hedge accounting, the effective portion of the changes in the fair value of the contracts is recorded in other comprehensive income on the balance sheet and
the ineffective portion of the changes in the fair value of the contracts is recorded in total revenue on the statement of operations, in either case as such changes occur. When the hedged production
is sold, the realized gains and losses on the contracts are removed from other comprehensive income and recorded
in revenue. While the contract is outstanding, the unrealized and ineffective gain or loss may increase or decrease until settlement of the contract depending on the fair value at the measurement
dates.

Beginning
in the first quarter of 2006, we applied mark-to-market accounting treatment to all outstanding derivative contracts, therefore the changes in fair
value are not deferred through other comprehensive income, but rather recorded in revenue immediately as unrealized gains or losses. Going forward, we will continue to evaluate the terms of new
contracts entered into to determine whether cash flow hedge accounting treatment or mark-to-market accounting treatment will be applied. Prior to 2006, we used
mark-to-market accounting treatment for our crude oil derivative contracts and cash flow hedge accounting treatment for our natural gas derivative contracts. Therefore,
unrealized gains and losses on the change in fair value of natural gas derivative contracts between periods may not be comparable.

16

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The table below shows derivative gains and losses included within total revenue for the years presented.

|                                                                                                          |                                        | Year Ended December 31 |        
|--------------------------------------------------------------------------------------------------------- | -------------------------------------- | ---------------------- | -------
|
|
|Natural gas contract settlements (Mcf)                                                                    |                                        | $                      | 4,513  
|Crude oil contract settlements (Bbl)                                                                      |                                        |                        | (935   
|Mark-to-market reversal of prior period unrealized change in fair value of gas derivative contracts (Mcf) |                                        |                        | (4,686 
|Mark-to-market unrealized change in fair value of gas derivative contracts (Mcf)                          |                                        |                        | 2,626  
|Mark-to-market reversal of prior period unrealized change in fair value of oil derivative contracts (Bbl) |                                        |                        | (500   
|Mark-to-market unrealized change in fair value of oil derivative contracts (Bbl)                          |                                        |                        | (14,956
|                                                                                                          |                                        |                        |        
|                                                                                                          | Gain (loss) on hedging and derivatives |                        | $      
|                                                                                                          |                                        |                        |        

The
table below summarizes our outstanding derivative contracts reflected on the balance sheet at December 31, 2007 and 2006.

|                |       |  |           |  |            |  |            |  |                 |  |              | Fair Value of Outstanding
Derivative Contracts as of
December 31, |        
|--------------- | ----- |  | --------- |  | ---------- |  | ---------- |  | --------------- |  | ------------ | ----------------------------------------------------------------- | -------
|
|
|
|Natural Gas(1): |       |  |           |  |            |  |            |  |                 |  |              |                                                                   |        
|                | 08/06 |  | Collar(3) |  | 01/01/2007 |  | 12/31/2007 |  | $7.50 - $11.50  |  | 5,000 MMBtu  |                                                                   | $      
|                | 08/06 |  | Collar(3) |  | 01/01/2007 |  | 12/31/2007 |  | $7.50 - $12.00  |  | 5,000 MMBtu  |                                                                   |        
|                | 01/07 |  | Collar    |  | 01/01/2008 |  | 12/31/2008 |  | $7.50 - $  9.00 |  | 20,000 MMBtu |                                                                   |        
|                | 01/07 |  | Collar    |  | 01/01/2008 |  | 12/31/2008 |  | $7.50 - $  9.00 |  | 10,000 MMBtu |                                                                   |        
|                | 01/07 |  | Collar    |  | 01/01/2008 |  | 12/31/2008 |  | $7.50 - $  9.02 |  | 10,000 MMBtu |                                                                   |        
|                | 04/07 |  | Collar    |  | 01/01/2009 |  | 12/31/2009 |  | $7.75 - $10.00  |  | 10,000 MMBtu |                                                                   |        
|                | 10/07 |  | Collar    |  | 01/01/2009 |  | 12/31/2009 |  | $7.75 - $10.08  |  | 10,000 MMBtu |                                                                   |        
|Crude Oil(2):   |       |  |           |  |            |  |            |  |                 |  |              |                                                                   |        
|                | 08/06 |  | Collar    |  | 01/01/2007 |  | 12/31/2007 |  | $70.00 - $87.50 |  | 400 Bbl      |                                                                   |        
|                | 12/06 |  | Swap      |  | 01/01/2007 |  | 12/31/2007 |  | $66.00          |  | 600 Bbl      |                                                                   |        
|                | 12/06 |  | Swap      |  | 01/01/2008 |  | 12/31/2008 |  | $66.00          |  | 1,500 Bbl    |                                                                   |        
|                | 10/07 |  | Collar    |  | 01/01/2009 |  | 12/31/2009 |  | $70.00 - $93.55 |  | 300 Bbl      |                                                                   |        
|                |       |  |           |  |            |  |            |  |                 |  |              |                                                                   |        
|                |       |  |           |  |            |  |            |  |                 |  |              | $                                                                 | (12,329
|                |       |  |           |  |            |  |            |  |                 |  |              |                                                                   |        

---

17

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Sales to Major Customers

We sold natural gas and crude oil production representing 10% or more of our total revenues to the following major customers for the years ended
December 31, 2007, 2006, and 2005.

For the Year Ended
December 31,Purchaser2007

2006

2005Integrys Energy Services, Inc.

22
%
*

*Kinder Morgan

20
%
37
%
29
%Gulfmark Energy, Inc.

11
%
5
%
6
%Copano Field Services

5
%
10
%
17
%ChevronTexaco, Inc.

4
%
12
%
18
%Kerr-McGee Oil & Gas

*

10
%
*






In
the exploration, development and production business, production is normally sold to relatively few customers. Substantially all our customers are concentrated in the oil and gas
industry, and our revenue can be materially affected by current economic conditions and the price of certain commodities such as natural 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 fact that alternate purchasers are readily available, we believe that the loss of any of our major purchasers would
not have a long-term material adverse effect on our operations.

Competition

We compete with other oil and natural gas companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Our
ability to explore for oil and natural gas reserves and to acquire additional properties in the future will be dependent upon our ability to conduct our operations, to evaluate and select suitable
properties and to consummate transactions in this highly competitive environment. We believe that our technological expertise, our exploration, land, drilling and production capabilities and the
experience of our management generally enable us to compete effectively. (SeeITEM 1A. "RISK FACTORSWe face strong competition from larger
oil and natural gas companies.")

INDUSTRY REGULATIONS

The availability of a ready market for oil and natural gas production depends upon numerous factors beyond our control. These factors include regulation of oil
and natural gas production, federal and state regulations governing environmental quality and pollution control, state limits on allowable rates of production by well or proration unit, the amount of
oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive
natural gas well may be "shut-in" because of an oversupply of natural gas or lack of an available natural gas pipeline in the areas in which we may conduct operations. State and federal
regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural
gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. We are
also subject to changing and extensive tax laws, the effects of which

18

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cannot
be predicted. The following discussion summarizes the regulation of the United States oil and natural gas industry. We believe that we are in substantial compliance with the various statutes,
rules, regulations and governmental orders to which our operations may be subject, although there can be no assurance that this is or will remain the case. Moreover, such statutes, rules, regulations
and government orders may be changed or reinterpreted from time to time in response to economic or political conditions, and there can be no assurance that such changes or reinterpretations will not
materially adversely affect our results of operations and financial condition. The following discussion is not intended to constitute a complete discussion of the various statutes, rules, regulations
and governmental orders to which our operations may be subject.

Regulation of Oil and Natural Gas Exploration and Production.Our operations are subject to various types of regulation at
the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the
location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids
used in connection with operations. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration
units and the density of wells that may be drilled in and the unitization or pooling of oil and natural gas properties. In this regard, some states allow the forced pooling or integration of tracts to
facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and
therefore more difficult to develop a project, if the operator owns less than 100% of the leasehold. In addition, state conservation laws which establish maximum rates of production from oil and
natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount
of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. The regulatory burden on the oil and natural gas industry increases our
costs of doing business and, consequently, affects our profitability. Inasmuch as such laws and regulations are frequently expanded, amended and interpreted, we are unable to predict the future cost
or impact of complying with such regulations.

Regulation of Sales and Transportation of Natural Gas.Federal legislation and regulatory controls have historically affected
the price of natural gas produced by us, and the manner in which such production is transported and marketed. Under the Natural Gas Act ("NGA") of 1938, the Federal Energy Regulatory Commission (the
"FERC") regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act (the "Decontrol
Act") 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 produced natural gas may now be sold at
market prices, subject to the terms of any private contracts that may be in effect. However, the Decontrol Act did not affect the FERC's jurisdiction over natural gas transportation. Under the
provisions of the Energy Policy Act of 2005 (the "2005 Act"), the NGA has been amended to prohibit any forms of market manipulation in connection with the purchase or sale of natural gas, and the FERC
has issued new regulations to implement this prohibition. In addition, under the 2005 Act the FERC has been directed to establish new regulations that are intended to increase natural gas pricing
transparency through, among other things, expanded dissemination of information about the availability and prices of gas sold. The 2005 Act also has significantly increased the penalties for
violations of the NGA.

Our
natural gas sales are affected by intrastate and interstate gas transportation regulation. Following the Congressional passage of the Natural Gas Policy Act of 1978 ("NGPA"), the
FERC adopted a series of regulatory changes that have significantly altered the transportation and marketing of natural gas. Beginning with the adoption of Order No. 436, issued in October
1985, the FERC has

19

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implemented
a series of major restructuring orders that have required pipelines, among other things, to perform "open access" transportation of gas for others, "unbundle" their sales and
transportation functions, and allow shippers to release their unneeded capacity temporarily and permanently to other shippers. As a result of these changes, sellers and buyers of gas have gained
direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access
to markets while, at the same time, substantially increasing competition in the natural gas marketplace. It remains to be seen, however, what effect the FERC's other activities will have on access to
markets, the fostering of competition and the cost of doing business. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent
regulations may have on our activities. We do not believe that we will be affected by any such new or different regulations materially differently than any other seller of natural gas with which we
compete.

In
the past, Congress has been very active in the area of gas regulation. However, as discussed above, the more recent trend has been in favor of deregulation, or "lighter handed"
regulation, and the promotion of competition in the gas industry. There regularly are other legislative proposals pending in the Federal and state legislatures that, if enacted, would significantly
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 and what effect, if any,
such proposals might have on us. Similarly, and despite the trend toward federal deregulation of the natural gas industry, we cannot predict whether or to what extent that trend will continue, or what
the ultimate effect will be on our sales of gas. Again, we do not believe that we will be affected by any such new legislative proposals materially differently than any other seller of natural gas
with which we compete.

We
own certain natural gas pipelines that we believe meet the standards the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA.
These gathering facilities are regulated for safety compliance by the U.S. Department of Transportation ("DOT") and/or by state regulatory agencies. In 2004, the DOT implemented regulations requiring
that pipeline operators implement a pipeline integrity management program that must at a minimum include an inspection of certain pipeline facilities within ten years, and at least every seven years
thereafter. In addition, beginning in early 2006, the DOT's Pipeline and Hazardous Materials Safety Administration commenced a rulemaking proceeding to develop rules that would better distinguish
onshore gathering lines from production facilities and transmission lines, and to develop safety requirements better tailored to gathering line risks. We are not able to predict with certainty the
final outcome of this rulemaking proposal.

The
intrastate pipeline system in Texas is regulated for safety compliance by the DOT and the Texas Railroad Commission. In 2002, the United States Congress enacted the Pipeline Safety
Improvement Act of 2002, which contains a number of provisions intended to increase pipeline operating safety. The DOT's final regulations implementing the 2002 act became effective in February 2004.
Among other provisions, the regulations require that pipeline operators implement a pipeline integrity management program that must at a minimum include an inspection of gas transmission pipeline and
nonrural gathering facilities within the next ten years, and at least every seven years thereafter. In December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement and Safety Act
of 2006, which reauthorizes the programs adopted under the 2002 Act, proposes enhancements for state programs to reduce excavation damage to pipelines, establishes increased federal enforcement of
one-call excavation programs, and establishes a new program for review of pipeline security plans and critical facility inspections. In addition, beginning in October 2005, the DOT's
Pipeline and Hazardous Materials Safety Administration commenced a rulemaking proceeding to develop rules that would better distinguish onshore gathering lines from production facilities and
transmission lines, and to develop safety requirements better tailored to gathering line risks. On March 15, 2006, the DOT revised its regulations to define more clearly the categories of
gathering

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facilities
subject to DOT regulation, established new safety rules for certain gathering lines in rural areas, revised the current regulations applicable to safety and inspection of gathering lines in
nonrural areas, and adopted new compliance deadlines. We acquired several lines in the January 2007 Acquisition that are subject to annual inspection and maintenance and we have DOT permits on 10
lines with the Texas Railroad Commission. In addition to safety regulation, state regulation of gathering facilities generally includes various environmental, and in some circumstances,
nondiscriminatory take requirements, but does not generally entail rate regulation. Natural gas gathering may receive greater regulatory rate and service scrutiny at the state level in the
post-restructuring environment.

Oil Price Controls and Transportation Rates.Sales of crude oil, condensate and gas liquids by us are not currently regulated
and are made at market prices. The price we receive from the sale of these products 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 FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an
indexing system for those rates 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 increase the 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 annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In March 2006, to
implement the second of the required five-yearly re-determinations, the FERC established an upward adjustment in the index to track oil pipeline cost changes. The FERC
determined that the Producer Price Index for Finished Goods plus 1.3 percent (PPI plus 1.3 percent) should be the oil pricing index for the five-year period beginning
July 1, 2006. We are not able at this time to predict the effects of these regulations or FERC proceedings, if any, on the transportation costs associated with oil production from our oil
producing operations.

Environmental Regulations.Our operations are subject to numerous federal, state and local laws and regulations governing the
discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict
the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on
certain lands within wilderness, wetlands and other protected areas, require remedial measures to mitigate pollution from former operations, such as pit closure and plugging abandoned wells, and
impose substantial liabilities for pollution resulting from production and drilling operations. Public interest in the protection of the environment has increased dramatically in recent years. The
trend of more expansive and stricter environmental legislation and regulations applied to the oil and natural gas industry could continue, resulting in increased costs of doing business and
consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly waste handling, disposal and
cleanup requirements, our business and prospects could be adversely affected.

We
generate wastes that may 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 limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Furthermore, certain wastes generated by our oil and natural gas operations that are
currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements.

We
currently own or lease numerous properties that for many years have been used for the exploration and production of oil and natural gas. Although we believe that we have used good
operating and waste disposal practices, prior owners and operators of these properties may not have

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used
similar practices, and hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under locations where such wastes have been
taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These
properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws as well as state laws
governing the management of oil and natural gas wastes. Under such laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior
owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination.

Our
operations may be subject to the Clean Air Act ("CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that have
resulted in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states developed and continue to develop regulations to
implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining
operating permits and approvals addressing other air emission-related issues. However, we do not believe our operations will be materially adversely affected by any such requirements.

In
response to studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to warming of the Earth's atmosphere, the current session of the U.S.
Congress is considering climate change-related legislation to restrict greenhouse gas emissions. One bill recently approved by the U.S. Senate Environment and Public Works Committee, known as the
Lieberman-Warner Climate Security Act or S.2191, would require a 70% reduction in emissions of greenhouse gases from sources within the United States between 2012 and 2050. The Lieberman-Warner bill
proposes a "cap and trade" scheme of regulation of greenhouse gas emissionsa ban on emissions above a defined reducing annual cap. Covered parties will be authorized to emit greenhouse
emissions through the acquisition and subsequent surrender of emission allowances that may be traded or acquired on the open market. A vote on this bill by the full Senate is expected to occur before
mid-year 2008. In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas
emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs require either major sources of emissions, such as electric power plants, or major
producers of fuels, such as refineries or gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall
greenhouse gas emission reduction goal is achieved.

Depending
on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of
oil or natural gas we produce. Although we would not be impacted to a greater degree than other similarly situated
producers of oil and natural gas, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the oil and natural gas we produce.

Also,
as a result of the U.S. Supreme Court's decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate carbon dioxide and other greenhouse
gas emissions from mobile sources such as cars and trucks, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The EPA has indicated that it will
issue a rulemaking notice to address carbon dioxide and other greenhouse gas emissions from vehicles and automobile fuels, although the date for issuance of this notice has not been finalized. The
Court's holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal Clean Air Act's definition of "air pollutant" may also result in future regulation of carbon
dioxide and other greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New federal

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or
state restrictions on emissions of carbon dioxide that may be imposed in areas of the United States in which we conduct business could also adversely affect our cost of doing business and demand
for the oil and natural gas we produce.

Federal
regulations require certain owners or operators of facilities that store or otherwise handle oil, such as Edge, to prepare and implement spill prevention, control, countermeasure
("SPCC") and response plans relating to the possible discharge of oil into surface waters. SPCC plans at our producing properties were developed and implemented in 1999. The Oil Pollution Act of 1990
("OPA") contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict joint and several
liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters.
Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Our operations are also subject to the federal Clean Water Act ("CWA") and analogous state laws. In
accordance with the CWA, the state of Louisiana has issued regulations prohibiting discharges of produced water in state coastal waters effective July 1, 1997. Like OPA, the CWA and analogous
state laws relating to the control of water pollution provide varying civil and criminal penalties and liabilities for releases of petroleum or its derivatives into surface waters or into the ground.

CERCLA,
also known as the "Superfund" law, and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that
are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred
and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be
subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain
health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released
into the environment.

We
also are subject to a variety of federal, state and local permitting and registration requirements relating to protection of the environment. Management believes that we are in
substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse effect on us.

OPERATING HAZARDS AND INSURANCE

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

In
accordance with customary industry practice, we maintain insurance against some, but not all, of the risks described above. Our insurance does not cover business interruption or
protect against loss of revenue. There can be no assurance that any insurance obtained by us will be adequate to cover any losses or liabilities. We cannot predict the continued availability of
insurance or the availability of insurance at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could materially and adversely
affect our financial condition and operations.

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ITEM 1A.    RISK FACTORS

Our ongoing strategic assessment process, including any transaction that might result therefrom, may reduce productivity because of its impact on our management, current and
prospective employees and customers, suppliers and business partners.

Our management may be required to devote substantial time to activities related to the strategic assessment process and any transaction resulting therefrom, which
time could otherwise be devoted to pursuing other beneficial business opportunities.

In
addition, our current and prospective employees may be uncertain about their future roles and relationships with us. This uncertainty may affect our productivity or adversely affect
our ability to attract and retain key management and employees.

Our
customers and business partners may not be as willing to continue to do business with us on the same or similar terms because of the strategic assessment process or any resulting
transaction. Changes in these business relationships could materially and adversely affect our business and results of operations.

Oil and gas drilling is a speculative activity and involves numerous risks and substantial and uncertain costs which could adversely affect us.

Our growth will be materially dependent upon the success of our future drilling program. Drilling for oil and gas involves numerous risks, including the risk that
no commercially productive oil or natural
gas reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a
variety of factors beyond our control, including unexpected drilling conditions, pressure or irregularities in formations, unexpected communication with water-bearing zones, equipment failures or
accidents, adverse weather conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rigs or crews and the delivery of equipment. Our future
drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate
or our drilling success rate for activity within a particular geographic area may decline. We may ultimately not be able to lease or drill identified or budgeted prospects within our expected time
frame, or at all. We may not be able to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the
prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a
number of factors, including:



These
projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive oil or natural gas. See ITEM 7. "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSGENERAL OVERVIEWINDUSTRY AND ECONOMIC FACTORS" andITEMS 1
AND 2. "BUSINESS AND PROPERTIESCORE AREAS OF OPERATION."

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

Our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties,
are substantially 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 on
our financial results. Lower oil and natural gas prices also may reduce the amount of oil and natural gas that we can produce economically. Historically, the markets for oil and natural gas have been
volatile, and such markets are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of
and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. These factors include the level of consumer product demand, weather conditions,
domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions, the foreign supply of oil and natural gas, the price of foreign imports and
overall economic conditions. Declines in oil and natural gas prices may materially adversely affect our financial condition, liquidity, and ability to finance planned capital expenditures and results
of operations. SeeITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSRISK MANAGEMENT
ACTIVITIESDERIVATIVES AND HEDGING" andITEMS 1 AND 2. "BUSINESS AND PROPERTIESOIL AND NATURAL GAS RESERVES" and
"MARKETING."

We
have in the past (most recently in the third quarter of 2006) and may in the future be required to write down the carrying value of our oil and natural gas properties. This may happen
for several reasons, including a revision in reserve estimates and depression or unusual volatility in oil and natural gas prices. Whether we will be required to take such a charge will depend on the
prices for oil and natural gas at the end of any quarter (or at the respective subsequent pricing date) and the effect of reserve additions or revisions and capital expenditures during such quarter.
If a write down is required, it would result in a charge to earnings, but would not impact cash flow from operating activities.

We have hedged and may continue to hedge our production, which may result in our making cash payments, prevent us from receiving the benefit of increases in prices for oil and
natural gas or expose us to risk of financial loss at times when production is less than expected.

In order to reduce our exposure to short-term fluctuations in the price of oil and natural gas, we periodically enter into hedging arrangements. At
the time we enter into our hedging arrangements, they are intended to apply to only a portion of our expected production and thereby provide only partial price protection against declines in oil and
natural gas prices. Such hedging arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected, our customers fail to
purchase contracted quantities of oil or natural gas or a sudden, unexpected event materially impacts oil or natural gas prices. In that regard, our recent changes in expected 2008 production and
expected asset divestitures have resulted in our derivative contracts covering approximately 110% and 150% of our anticipated 2008 natural gas and crude oil production, respectively. This overhedged
position exposes us to greater risk of commodity price increases because we will not have the physical production cash inflows to offset any potential losses incurred on the portion of the contracts
that are overhedged. SeeITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSRISK
MANAGEMENT ACTIVITIESDERIVATIVES AND HEDGING" andITEMS 1 AND 2. "BUSINESS AND PROPERTIESDERIVATIVES."

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We depend on successful exploration, development and acquisitions to maintain reserves and revenue in the future.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir
characteristics. Except to the extent we acquire properties containing proved reserves or conduct successful exploration and 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 acquiring additional reserves. In addition, we are dependent on finding partners for our
exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we could be adversely affected.

We are subject to substantial operating risks that may adversely affect the results of our operations.

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

We
are not the operator of some of our wells. As a result, our operating risks for those wells and our ability to influence 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. SeeITEMS 1 AND 2. "BUSINESS AND
PROPERTIESOPERATING HAZARDS AND INSURANCE."

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

We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks
associated with, operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator's breach of the applicable agreements or an operator's failure to
act in ways that are in our best interest could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depend
upon a number of factors outside of our control, including the operator's



The loss of key personnel could adversely affect us.

We depend to a large extent on the services of certain key management personnel, including our executive officers and other key employees, the loss of any of
which could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any of our employees. We believe that our success is also dependent
upon our ability to continue to employ and retain skilled technical personnel. SeeITEM 4. "SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERSEXECUTIVE OFFICERS OF THE REGISTRANT" and "SIGNIFICANT EMPLOYEES."

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

We have experienced and expect to continue to experience substantial working capital needs due to our ongoing exploration, development and acquisition programs.
Additional financing may be required in the future to fund our growth. We may not be able to obtain such additional financing, and financing under existing or new credit facilities may not be
available in the future. In the event such capital resources are not available to us, our drilling and other activities may be curtailed. SeeITEM 7. "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSLIQUIDITY AND CAPITAL RESOURCES."

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

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

Government regulation and liability for environmental matters may adversely affect our business and results of operations.

Oil and natural gas operations are subject to various federal, state and local government regulations, which may be changed from time to time. Matters subject to
regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to
time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity in order to conserve
supplies of oil and natural gas. There are federal, state and local laws and regulations primarily relating to protection of human health and the environment applicable to the development, production,
handling, storage, transportation and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas
operations. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. As a result, we may incur substantial liabilities to third parties or
governmental entities. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The implementation of new, or the modification of existing, laws or regulations
could have a material adverse effect on us. SeeITEMS 1 AND 2. "BUSINESS AND PROPERTIESINDUSTRY REGULATIONS."

We may have difficulty managing any future growth and the related demands on our resources and may have difficulty in achieving future growth.

We have experienced growth in the past through the expansion of our drilling program and, more recently, acquisitions. This expansion was curtailed in 1998 and
1999, but resumed in 2000 and increased in subsequent years. Any future growth may place a significant strain on our financial, technical, operational and administrative resources. In particular, the
January 2007 Acquisition has resulted in a significant growth in our assets, reserves and revenues and may place a significant strain on our financial, technical, operational and administrative
resources.

Our
ability to grow will depend upon a number of factors, including our ability to identify and acquire new exploratory prospects, our ability to develop existing prospects, our ability
to continue to retain and attract skilled personnel, the results of our drilling program and acquisition efforts,

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hydrocarbon
prices and access to capital. We may not be successful in achieving or managing growth and any such failure could have a material adverse effect on us.

We face strong competition from larger oil and natural gas companies.

The oil and gas industry is highly competitive. We encounter competition from oil and natural gas companies in all areas of our operations, including the
acquisition of exploratory prospects and productive oil and natural gas properties. Our competitors range in size from the major integrated oil and natural 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 with substantially larger operating staffs and
greater capital resources than ours. We may not be able to conduct our operations successfully, evaluate and select suitable properties, consummate transactions, and obtain technical, managerial and
other professional personnel in this highly competitive environment. Specifically, these larger competitors may be able to pay more for exploratory prospects, productive oil and natural gas properties
and competent personnel and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such
competitors may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. Such
competitors may also be in a better position to secure oilfield services and equipment on a timely basis or on favorable terms. SeeITEMS 1 AND 2. "BUSINESS AND
PROPERTIESCOMPETITION."

The oil and natural gas reserve data included in or incorporated by reference in this document are estimates based on assumptions that may be inaccurate and existing economic
and operating conditions that may differ from future economic and operating conditions.

Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact
manner and is based upon assumptions that may vary considerably from actual results. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and
expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. The information regarding discounted future net cash flows included in this report should
not be considered as the current market value of the estimated oil and natural gas reserves attributable to our properties. As required by the SEC, the estimated discounted future net cash flows from
proved reserves are based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected
by factors such as the amount and timing of actual production, supply and demand for oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation. In
addition, the 10% discount factor, which is required by Financial Accounting Standards Board in SFAS No. 69,Disclosures About Oil and Natural Gas Producing
Activitiesto be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with us or the oil and natural gas industry in general. SeeITEMS 1 AND 2. "BUSINESS AND
PROPERTIESOIL AND NATURAL GAS RESERVES."

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

Over the past few years, increases in commodity prices, in proved reserve amounts and the resultant increase in estimated discounted future net revenue, has
allowed us to increase our available borrowing amounts. In the future, commodity prices may decline, reserve estimates may be revised, we may increase our borrowings or our borrowing base may be
adjusted downward. Our credit facility is secured by a pledge of substantially all of our assets and has covenants that limit additional borrowings,

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sales
of assets and the distributions of cash or properties and that prohibit the payment of dividends on our common stock and the incurrence of liens. The credit facility also requires that specified
financial ratios be maintained. The restrictions of our credit facility and the difficulty in obtaining additional debt financing may have adverse consequences on our operations and financial results,
including our ability to obtain financing for working capital, capital expenditures, our drilling program, purchases of new technology or other purposes. In addition, such financing may be on terms
unfavorable to us and we may be required to use a substantial portion of our cash flow to make debt service payments, which will reduce the funds that would otherwise be available for operations and
future business opportunities. Further, a substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and require us
to modify operations, and thus we may become more vulnerable to downturns in our business or the economy generally.

Our
ability to obtain and service indebtedness will depend on our future performance, 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 or above anticipated levels or we may not be able to borrow funds in amounts sufficient to enable us to service
indebtedness, make anticipated capital expenditures or finance our drilling program. If we are unable to generate sufficient cash flow from operations or to borrow sufficient funds in the future to
service our debt, we may be required to curtail portions of our drilling program, sell assets, reduce capital expenditures, refinance all or a portion of our existing debt or obtain additional
financing. We may not be able to refinance our debt or obtain additional financing, particularly in view of our strategic assessment process, current industry conditions, the restrictions on our
ability to incur debt under our existing debt arrangements, and the fact that substantially all of our assets are currently pledged to secure obligations under our credit facility. See ITEM 7. "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSLIQUIDITY AND CAPITAL RESOURCES" and
"CREDIT FACILITY."

We may not have enough insurance to cover all of the risks we face.

In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks
we face. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks
presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our
financial condition and results of operations.

Our acquisition program may be unsuccessful.

Acquisitions have become increasingly important to our business strategy in recent years. The successful acquisition of producing properties requires an
assessment of recoverable reserves, future oil and natural gas prices, operating costs, potential environmental and other liabilities and other factors. Such assessments, even when performed by
experienced personnel, are necessarily inexact and their accuracy inherently uncertain. Our review of subject properties will not reveal all existing or potential problems, deficiencies and
capabilities. We may not always perform inspections on every well, and may not be able to observe structural and environmental problems even when we undertake an inspection. Even when problems are
identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of such problems. We may be required to assume the risk of the physical condition of
the properties in addition to the risk that the properties may not perform in accordance with our expectations. We may be left with no recourse for liabilities and other problems associated with
acquisitions that we do not discover prior to the closing date. Any acquisition of property interests by us may not be successful and, if unsuccessful, such failure may have an adverse effect on our
future results of operations and financial condition.

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Our ability to utilize net operating loss carryforwards may be limited.

At December 31, 2007, we had estimated net operating loss carryforwards ("NOLs") of $146.5 million for federal income tax purposes that expire
beginning in 2012 and continuing through 2027. We also had state NOL carryforwards at December 31, 2007 of $19.2 million, which will expire in varying amounts between 2008 and 2027. See
Note 16 to our consolidated financial statements. Our ability to utilize federal NOL carryforwards in cases where the NOL was acquired in a reorganization may be subject to limitations under
Section 382 of the Internal Revenue Code of 1986, as amended ("Section 382") if we undergo a majority ownership change as defined by Section 382.

We
would undergo a majority ownership change if, among other things, the stockholders who own or have owned, directly or indirectly, five percent or more of our common stock or are
otherwise treated as five percent stockholders under Section 382 and the regulations promulgated thereunder, increase their aggregate percentage ownership of our stock by more than
50 percentage points over the lowest percentage of stock owned by these stockholders at any time during the testing period, which is generally the three-year period preceding the
potential ownership change. In the event of a majority ownership change, Section 382 imposes an annual limitation on the amount of taxable income a corporation may offset with the NOL
carryforwards. Any unused annual limitation may be carried over to later years until the applicable expiration of the respective NOL carryforwards. The amount of the limitation may, under certain
circumstances, be increased by built-in gains held by us at the time of the change that are recognized in the five year period after the change. If we were to undergo a majority ownership
change, we would be required to record a reserve for some or all of the asset currently recorded on our balance sheet. As of December 31, 2007, we believe that there may have been an additional
change of ownership pursuant to Section 382 as a result of the concurrent public offerings of our common and preferred stock that occurred in January 2007. We cannot make assurances that
we will not undergo a majority ownership change in the future because an ownership change for federal tax purposes can occur based on trades among our existing stockholders. Whether we undergo a
majority ownership change may be a matter beyond our control. Further, in light of the ongoing strategic assessment process, we cannot provide any assurance that a potential sale or merger will not
reduce the availability of our NOL carryforward and other federal income tax attributes, which may be significantly limited or possibly eliminated.

At
December 31, 2007, under Section 382 rules, approximately $77 million of our total federal NOL carryforward of $146.5 million was subject to a potential
annual limitation of $12 million. Of that $77 million, $22 million was subject to further annual limitations. The $22 million amount represents the following two separate
limitations which occurred prior to 2007: (1) $17.4 million acquired in a December 2003 merger, which is subject to an annual limitation of approximately $1 million per
year and (2) $5.4 million acquired in a November 2005 acquisition, which is subject to an annual limitation of approximately $2 million per year.

Approximately 23% of our proved reserves were undeveloped as of December 31, 2007, and those reserves may not ultimately be developed.

As of December 31, 2007, approximately 23% of our proved reserves were undeveloped. Proved undeveloped reserves, by their nature, are less certain than
other categories of proved reserves. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations and involves greater risks. Our reserve data for the
properties assumes that to develop our reserves we will make significant capital expenditures and conduct these operations successfully. Although we have prepared estimates of these natural gas and
oil reserves and the costs associated with these reserves in accordance with industry standards and SEC requirements, the estimated costs may not be accurate, development may not occur as scheduled
and actual results may not be as estimated.

30

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We do not intend to pay dividends on our common stock and our ability to pay dividends on our common stock is restricted.

We have not historically paid a dividend on our common stock, cash or otherwise, and do not intend to in the foreseeable future. We are currently restricted from
paying dividends on common stock by our existing credit facility agreement and, in some circumstances, by the terms of our Series A preferred stock. Any future dividends also may be restricted
by our then-existing debt agreements. SeeITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONSLIQUIDITY AND CAPITAL RESOURCES" and Notes 10 and 12 to our consolidated financial statements.

Our reliance on third parties for gathering and distributing could curtail future exploration and production activities.

The marketability of our production depends upon the proximity of our reserves to, and the capacity of, third-party facilities and services, including oil and
natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities. The unavailability or lack of capacity of such services and facilities could result in the
shut-in of producing wells or the delay or discontinuance of development plans for properties. A shut-in or delay or discontinuance could adversely affect our financial
condition. In addition, federal and state regulation of oil and natural gas production and transportation affect our ability to produce and market our oil and natural gas on a profitable basis.

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

Our Certificate of Incorporation and Bylaws and the Delaware General Corporation Law contain provisions that may have the effect of delaying, deferring or
preventing a change of control of the Company. These provisions, among other things, provide for a classified Board of Directors with staggered terms, restrict the ability of stockholders to take
action by written consent, authorize the
Board of Directors to set the terms of Preferred Stock, and restrict our ability to engage in transactions with stockholders with 15% or more of outstanding voting stock.

Because
of these provisions, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our Board of Directors rather than
pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent Board
of Directors.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

None.

CERTAIN DEFINITIONS

The definitions set forth below shall apply to the indicated terms as used in this Annual Report. All volumes of natural gas referred to herein are stated at the
legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

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

Bbl.One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid
hydrocarbons.

Bbls/d.Stock tank barrels per day.

31

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Bcf.Billion cubic feet.

Bcfe.Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate
or natural gas liquids.

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

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

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

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

Dry holeorwell.A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production exceed the related oil and natural gas operating expenses and taxes.

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

Farm-inorfarm-out.An agreement whereunder the
owner of a working interest in an oil and natural gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is
required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty 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 or multiple reservoirs all grouped on or related to the same individual
geological structural feature and/or stratigraphic condition.

Finding costs.Costs associated with acquiring and developing proved oil and natural gas reserves which are capitalized by us
pursuant to generally accepted accounting principles in the United States, including all costs involved in acquiring acreage, geological and geophysical work and the cost of drilling and completing
wells, excluding those costs attributable to unproved property.

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

MBbls.One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf.One thousand cubic feet.

Mcf/d.One thousand cubic feet per day.

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

MMcf.One million cubic feet.

32

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MMcf/d.One million cubic feet per day.

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

MMcfe/d.One million cubic feet equivalent per day.

Net acresornet wells.The sum of the fractional working interests owned in
gross acres or gross wells.

NGL's.Natural gas liquids measured in barrels.

NRIorNet Revenue Interests.The share of production after satisfaction of
all royalty, overriding royalty, oil payments and other nonoperating interests.

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

Over-pressured reservoirs.Reservoirs with a formation fluid pressure greater than 0.465 PSI per foot of depth
from the surface.

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

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

Productive well.A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds
from the sale of such production exceeds production expenses and taxes.

Proved developed nonproducing reserves.Proved developed reserves expected to be recovered from zones behind casing in
existing wells.

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

Proved developed reserves.Proved reserves that can be expected to be recovered 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
data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

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

Proved undeveloped reserves.Proved reserves that are expected to be recovered from new wells on undrilled acreage or from
existing wells where a relatively major expenditure is required for recompletion.

Recompletion.The completion for production of an existing well bore in another formation from that in which the well has
been previously completed.

33

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Reservoir.A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural
gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

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

3-D seismic.Advanced technology method of detecting accumulations of hydrocarbons identified through a
three-dimensional picture of the subsurface created by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

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

Working interestorWI.The operating interest that gives the owner the right
to drill, produce and conduct operating activities on the property and a share of production.

Workover.Operations on a producing well to restore or increase production.

ITEM 3.    LEGAL PROCEEDINGS

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

Wade and Joyce Montet, et al., v. Edge Petroleum Corp of Texas, et al., consolidated with Rolland L. Broussard, et al., v. Edge Petroleum Corp of
Texas, et al.This was a consolidated suit, filed in state court in Vermilion Parish, Louisiana in September 2003. Plaintiffs were mineral/royalty
owners under the Norcen-Broussard No. 1 and 2 wells, Marg Tex Reservoir C, Sand Unit A (Edge's old Bayou Vermilion Prospect). They claimed the operator at the time, Norcen Explorer, now
Anadarko E&P Company ("Anadarko"), failed to "block squeeze" the sections of the No. 2 well, as a prudent operator, according to their allegations, would have done, to protect the gas reservoir
from being flooded with water from adjacent underground formations. Plaintiffs further alleged Norcen Explorer was negligent in not creating a field-wide unit to protect their interests.
The allegations related to actions taken beginning in the early 1990's. Plaintiffs named us and other working interest owners in the leases as defendants, including Norcen Explorer's successors in
interest, Anadarko. Plaintiffs originally sought damages, including interest, as high as $63 million for lost royalties and damages due to alleged devaluation of their mineral and property
interests, plus attorneys' fees. Of the 18.75% after-payout working interest that was originally reserved in the leases, we owned a 2.8% working interest at the time of the alleged acts or omissions.
On September 6, 2005, we filed a third-party demand to join the other working interest owners who hold the remainder of the 18.75% working interest as third-party defendants in this case. These
third-parties consist, for the most part, of partnerships that are directly or indirectly controlled by John Sfondrini, a director of Edge, and hold an aggregate 14.7% working interest (the "Sfondrini
Partnerships"). Vincent Andrews, also a director of Edge, owns a minority interest in the corporate general partner of one of the partnerships. The Sfondrini Partnerships consist of (1) Edge
Group Partnership, a general partnership composed of limited partnerships of which Mr. Sfondrini and a company controlled by Mr. Sfondrini are general partners; (2) (A) Edge
Option I Limited Partnership, (B) Edge Option 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, 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 party

34

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defendants
that we have sought to join in the case, and these partnerships have for the most part filed answers denying any liability to us.

Broussard Plaintiff Settlement.

On December 19, 2006, we, along with the other defendants in this suit, reached a settlement agreement with the Broussard Plaintiffs in full settlement of
their 72% of the total claims made in this consolidated action. This settlement was finalized in January 2007. Our share of this settlement totaled approximately $208,000, which was recorded in
December 2006, and the Sfondrini Partnerships' share totaled $1,109,759. The settlement with the Broussard Plaintiffs was finalized on February 1, 2007, and the defendants and the third-party
defendants including the Sfondrini Partnerships were released from all claims by the Broussard Plaintiffs.

The
Sfondrini Partnerships did not have sufficient cash to fund their respective full portion of the settlement. Therefore, in order to facilitate the settlement, we purchased certain
oil and gas properties from certain of the Sfondrini Partnerships, with the proceeds of such sale and purchase generally being directed to payment of the Broussard settlement, in full satisfaction of
the Sfondrini Partnerships' share of such settlement. The oil and gas properties that we purchased from the Sfondrini Partnerships and their respective purchase prices are as follows:



In
the purchase and sale transaction between us and the Sfondrini Partnerships, BV Partners Limited Partnership, whose 2.48% share of the Broussard settlement amount was $186,000
(as determined by us and Mr. Sfondrini on behalf of the BV Partners Limited Partnership), did not sell any assets to us and did not have sufficient funds to satisfy its share of the
settlement amount. In addition, the Edge Option I, II and III Limited 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, II and 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 Group Partnership sold additional properties (over the amount necessary to
fund its portion of the settlement) to us at fair market value in an amount sufficient to allow it to have proceeds from such sale to fund BV Partners Limited Partnership's share of the
settlement and the remaining shortfall amounts owed by Edge Option I, II and III. In return, BV Partners and Edge Option I, II and III contributed all of their interest in the Bayou Vermilion
Prospect leases and the Trahan No. 3 well located thereon to Edge Group Partnership. The fair market value of these interests contributed to Edge Group by BV Partners Limited Partnership
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.

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

35

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Montet Plaintiff Settlement.

We and the other oil company defendants participated in a mediation regarding the remaining claims in this lawsuit with the Montet plaintiffs on May 10,
2007. All remaining claims were settled for a total agreed payment to the Montet plaintiffs of $3.5 million. Our and the Sfondrini Partnerships' share of the settlement amount were $118,333 and
$502,917, respectively, for a total of $621,250, which amounts were paid by insurance. As part of the settlement, Mid-Continent Casualty Company and one other insurer agreed to cover and
pay the full share of the Montet settlement amount attributable to us and the Sfondrini Partnerships in return for mutual releases under the policies involved and for a joint dismissal of all claims
asserted by the parties in the suit for declaratory judgment filed by Mid-Continent against us and the Sfondrini Partnerships in federal district court in Houston. Also as part of the
settlement, we reimbursed the Sfondrini Partnerships for certain attorneys' fees in the amount of $62,500. The settlement with the Montet plaintiffs was finalized in writing in June 2007, all
defendants have paid their respective shares of the amounts owed, and the court entered an order to dismiss on August 3, 2007. A final judgment dismissing all claims with prejudice was filed on
June 29, 2007 in the related Mid-Continent suit for declaratory judgment in federal district court in Houston.

David Blake, et al. v. Edge Petroleum CorporationOn September 19, 2005, David Blake and
David Blake, Trustee of the David and Nita Blake 1992 Children's Trust filed suit against us in state district court in Goliad County, Texas alleging breach of contract for failure and refusal to
transfer overriding royalty interests to plaintiffs in several leases in Goliad County, Texas and failure and refusal to pay monies to Blake pursuant to such overriding royalty interests for wells
completed on the leases. The plaintiffs seek relief of (1) specific performance of the alleged agreement, including granting of overriding royalty interests by the Company to Blake;
(2) monetary damages for failure to grant the overriding royalty interests; (3) exemplary damages for his claims of business disparagement and slander; (4) monetary damages for
tortuous interference; and (5) attorneys' fees and court costs. Venue of the case was transferred to Harris County, Texas by agreement of the litigants. We have served plaintiffs with discovery
and have filed a counterclaim and an amended counterclaim joining various related entities that are controlled by plaintiffs. In addition, plaintiffs have filed an amended complaint alleging claims of
slander of title and tortuous interference related to its alleged right to receive an overriding royalty interest from a third party. Plaintiffs currently have on file an amended motion for summary
judgment, to which we have filed a response. In addition, we have filed a motion for summary judgment on the plaintiffs' case. In December 2006, the court denied our motion for summary judgment. The
court has not ruled on Blake's motion. In November 2007, we filed a separate motion for summary judgment based on the statute of frauds; the court has not ruled on this separate motion. The trial,
originally scheduled to begin September 10, 2007, and reset for March 3, 2008, has
been continued until August 20, 2008. Discovery in the case has commenced and is continuing. We have responded aggressively to this lawsuit, and believe we have meritorious defenses and
counterclaims.

Diana Reyes, et al. v. Edge Petroleum Operating Company, Inc., et al.On January 8,
2008, we were served with a wrongful death action filed in Hidalgo County, Texas. Plaintiffs allege negligence and gross negligence resulting from a fatality accident at the State B-12
well site, on our Bloomberg Flores lease in Starr County, Texas. The plaintiffs are the widow and minor children of Mr. Reyes, who was killed in a one-car fatality accident on
August 5, 2007. Mr. Reyes was an employee of our vendor, Payzone Logging. No specific amount of damages has been alleged to date; plaintiffs are asserting damages from loss of
companionship, pecuniary loss, pain and mental anguish, loss of inheritance and funeral and burial expenses. We may have insurance coverage for all or part of this claim. Our insurance carrier has
retained counsel to represent us in this matter. We filed an answer on January 30, 2008 denying plaintiffs' allegations and asserting defenses. We have not established a reserve with respect to
this claim and it is not possible to determine what, if any, our ultimate exposure might be in this matter. We will continue to respond aggressively to this lawsuit, and believe we have meritorious
defenses.

36

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ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

Executive Officers of the Registrant

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

John W. Eliashas served as the Chief Executive Officer and Chairman of the Board of the Company since November 1998. From April 1993 to
September 30, 1998, he served in various senior management positions, including Executive Vice President, of Seagull Energy Corporation, a company engaged in oil and natural gas exploration,
development and production and pipeline marketing. Prior to April 1993, Mr. Elias served in various positions for more than 30 years, including senior management positions with Amoco
Corporation, a major integrated oil and gas company. Mr. Elias has more than 40 years of experience in the oil and natural gas exploration and production business. He is 67 years
old.

Michael G. Longhas served as Executive Vice President and Chief Financial Officer of the Company since April 2005 and as Senior Vice
President and Chief Financial Officer since December 1996, and as Treasurer of the Company since October 2004. Mr. Long served as Vice President-Finance of W&T Offshore, Inc., an oil and
natural gas exploration and production company, from July 1995 to December 1996. From May 1994 to July 1995, he served as Vice President of the Southwest Petroleum Division for Chase Manhattan Bank,
N.A. Prior thereto, he served in various capacities with First National Bank of Chicago, most recently that of Vice President and Senior Corporate Banker of the Energy and Transportation Department,
from March 1992 to May 1994. Mr. Long received a B.A. in Political Science and a M.S. in Economics from the University of Illinois. Mr. Long is 55 years old.

John O. Tugwellhas served as Chief Operating Officer and Executive Vice President since April 2005 and prior to that served as Chief
Operating Officer and Senior Vice President of Production for the Company since March 2004. Prior to that, he served as Senior Vice President of Production since December 2001. Prior to that,
Mr. Tugwell served as Vice President of Production since March 1997. He served as Senior Petroleum Engineer of the Company's predecessor corporation since May 1995. From 1986 to May 1995,
Mr. Tugwell held various reservoir/production engineering positions with Shell Oil Company, most recently that of Senior Reservoir Engineer. Mr. Tugwell holds a B.S. in Petroleum
Engineering from Louisiana State University. Mr. Tugwell is a registered Professional Engineer in the State of Texas. Mr. Tugwell is 44 years old.

Significant Employees

C.W. MacLeodhas served as the Senior Vice President Business Development and Planning for the Company since April
2004 and Vice President Business Development and Planning for the Company since January 2002. From November 1999 to December 2001, he was Vice PresidentInvestment Banking with Raymond
James and Associates, Inc. From February 1990 to October 1999, Mr. MacLeod was a principal with Kirkpatrick Energy Associates, Inc., whose principal business was merger and
acquisition services, capital arrangement and analytical services for the oil and gas producing industry. Mr. MacLeod was responsible for originating corporate finance and research products for
energy clients. His previous experience includes positions as an independent petroleum geologist, a manager of exploration and production for an independent oil and gas producer and geologic positions
with Ladd Petroleum Corporation and Resource Sciences Corporation. Mr. MacLeod graduated from Eastern Michigan University with a B.S. in Geology and earned his M.B.A. from the University of
Tulsa. He is 57 years old.

37

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Howard Creaseyhas served as the Senior Vice President of Exploration since October 2006 and prior to that as the Vice President of
Exploration since October 2005. Before October 2005, Mr. Creasey was Chief Geologist for the Company since October 2003. From April of 1999 until October 2003 he served as a Senior Staff
Geologist for Devon Energy and its predecessor Ocean Energy. Prior to April 1999 for 14 years Mr. Creasey served as President and Exploration Geologist for Moss Rose Energy, Inc.,
a company he 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 is a Certified Geoscientist
in the State of Texas. Mr. Creasey is 52 years old.

Kirsten A. Hinkhas served as Vice President and Controller of the Company since October 2003 and as Controller of the Company since
December 31, 2000. Prior to that time she served as Assistant Controller from June 2000 to December 2000. Before joining Edge, she served as Controller of Benz Energy Inc., an oil and
gas exploration company, from June 1998 to June 2000. Mrs. Hink received a
B.S. in Accounting from Trinity University. Mrs. Hink is a Certified Public Accountant in the State of Texas. She is 41 years old.

David J. Panfelyhas served as Vice President Tax of the Company since May 2007. He was previously Director of Tax Reporting at
GlobalSantaFe Corporation since January 2001 and was with Apache Corporation for three years and with KPMG for over six years. He is a Certified Public Accountant in the State of Texas and is 47.

Kurt P. Primeauxhas served as Vice President of Production since October 2006, Manager of Production Operations from April 2004 to
October 2006, and before that, as Senior Petroleum Engineer from August 2003 to April 2004. Prior to joining the Company, he held similar positions with Union Oil of California from June 1998 to
August 2003, most recently that of Resource Manager. Mr. Primeaux began his career with Texaco USA in 1988 and has over 18 years experience in reservoir, drilling, production and
operations engineering. He holds a B.S. degree in Petroleum Engineering from Louisiana State University and an M.S. degree in Environmental Engineering from Tulane University. He is 44 years
old.

R. Keith Turnerhas served as Vice President of Land for the Company since September 2006. Before moving to the Land Department,
Mr. Turner was a Staff Attorney in the Legal Department since 2003. Prior to joining the Company in 2003, Mr. Turner served in various capacities with Newfield Exploration Company, 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 53 years old.

Robert C. Thomashas served as Senior Vice President, General Counsel and 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 served in similar capacities for the Company's corporate predecessor. From 1988 to January
1991, he was associate and acting general counsel for Mesa Limited Partnership in Amarillo, Texas. Mr. Thomas holds a B.S. degree in Finance and a J.D. degree in Law from the University of
Texas at Austin. He is 54 years old.

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PART II

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

Market Price of and Dividends on Common Equity and Related Stockholder Matters.

As of March 11, 2008, we estimate there were approximately 229 record holders of our common stock. Our common stock is listed on the NASDAQ Global Select
Market ("NASDAQ") and traded under the symbol "EPEX". As of March 11, 2008, we had 28,569,491 shares of common stock outstanding and our closing price on NASDAQ was $4.48 per share. The
following table sets forth, for the periods indicated, the high and low closing sales prices for our common stock as listed on NASDAQ.

Common Stock PricesHigh
($)

Low
($)Calendar 2007First Quarter

18.23

11.62Second Quarter

15.78

12.30Third Quarter

15.20

11.90Fourth Quarter

13.05

5.21Calendar 2006First Quarter

34.65

22.89Second Quarter

26.85

16.60Third Quarter

21.58

15.28Fourth Quarter

20.26

15.00


We
have never paid a dividend on our common stock, cash or otherwise, and do not intend to in the foreseeable future. In addition, under our current credit facility, we are restricted
from paying cash dividends on our common stock. The payment of future dividends, if any, will be determined by our Board of Directors in light of conditions then existing, including our earnings,
financial condition, capital requirements, restrictions in financing agreements, business conditions and other factors. SeeITEMS 1A. "RISK
FACTORSWe do not intend to pay dividends on our common stock and our ability to pay dividends on our common stock is restricted."

There
were no repurchases of securities during the fourth quarter of 2007.

39

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Performance Graph

The following performance graph compares the cumulative total stockholder return on the common stock to the cumulative total return of the Standard &
Poor's 500 Stock Index ("S&P 500 Index") and an index composed of all publicly traded oil and gas companies identifying themselves by primary Standard Industrial Classification ("SIC") Code
1311 (Crude Petroleum and Natural Gas) for the period beginning December 31, 2002 and ending December 31, 2007.

COMPARE 5-YEAR CUMULATIVE TOTAL RETURN
AMONG EDGE PETROLEUM CORPORATION, S&P 500 INDEX
AND SIC CODE 1311 INDEX

CHART

The
graph assumes that $100 was invested on December 31, 2002 in each of Edge common stock, the S&P 500 Index and the SIC Code 1311 companies and assumes that all dividends
were reinvested:

Edge Petroleum

SIC Code Index

S&P 500 IndexDecember 31, 2002

$
100.00

$
100.00

$
100.00December 31, 2003

$
269.87

$
160.61

$
128.68December 31, 2004

$
388.80

$
204.02

$
142.69December 31, 2005

$
664.27

$
293.12

$
149.70December 31, 2006

$
486.40

$
381.13

$
173.34December 31, 2007

$
158.13

$
535.76

$
182.87


40

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ITEM 6.    SELECTED FINANCIAL DATA

The following table sets forth selected financial data regarding the Company as of and for each of the periods indicated. The following data should be read in
conjunction withITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS"and ITEM 8. "FINANCIALS STATEMENTS AND SUPPLEMENTARY
DATA":

|                          |                                                                              | Year Ended December 31,                                                              |                         
|------------------------- | ---------------------------------------------------------------------------- | ------------------------------------------------------------------------------------ | ------------------------
|
|
|Statement of operations:  |                                                                              |                                                                                      |                         
|                          | Oil and natural gas revenue                                                  |                                                                                      | $                       
|                          | Operating expenses:                                                          |                                                                                      |                         
|                          |                                                                              | Oil and natural gas operating expenses including production and ad valorem taxes     |                         
|                          |                                                                              | Depletion, depreciation, amortization and accretion(6)                               |                         
|                          |                                                                              | Impairment of oil and natural gas properties(7)                                      |                         
|                          |                                                                              | General and administrative expenses and bad debt expense                             |                         
|                          |                                                                              |                                                                                      |                         
|                          |                                                                              |                                                                                      | Total operating expenses
|                          |                                                                              |                                                                                      |                         
|                          | Operating income (loss)                                                      |                                                                                      |                         
|                          |                                                                              | Interest expense and amortization of deferred loan costs, net of amounts capitalized |                         
|                          |                                                                              | Interest income                                                                      |                         
|                          |                                                                              |                                                                                      |                         
|                          | Income (loss) before income taxes and cumulative effect of accounting change |                                                                                      |                         
|                          |                                                                              | Income tax (expense) benefit                                                         |                         
|                          |                                                                              |                                                                                      |                         
|                          | Income (loss) before cumulative effect of accounting change                  |                                                                                      |                         
|                          |                                                                              | Cumulative effect of accounting change(6)                                            |                         
|                          |                                                                              |                                                                                      |                         
|                          | Net income (loss)                                                            |                                                                                      |                         
|                          | Preferred stock dividends                                                    |                                                                                      |                         
|                          |                                                                              |                                                                                      |                         
|                          | Net income (loss) available to common stockholders                           |                                                                                      | $                       
|                          |                                                                              |                                                                                      |                         
|                          | Basic earnings (loss) per share:                                             |                                                                                      |                         
|                          |                                                                              | Income (loss) before cumulative effect of accounting change                          |                         
|                          |                                                                              | Cumulative effect of accounting change                                               |                         
|                          |                                                                              |                                                                                      |                         
|                          |                                                                              | Basic earnings (loss) per share                                                      |                         
|                          |                                                                              |                                                                                      |                         
|                          | Diluted earnings (loss) per share:                                           |                                                                                      |                         
|                          |                                                                              | Income (loss) before cumulative effect of accounting change                          |                         
|                          |                                                                              | Cumulative effect of accounting change(6)                                            |                         
|                          |                                                                              |                                                                                      |                         
|                          |                                                                              | Diluted earnings (loss) per share                                                    |                         
|                          |                                                                              |                                                                                      |                         
|                          | Basic weighted average number of common shares outstanding(1)(8)             |                                                                                      |                         
|                          | Diluted weighted average number of common shares outstanding(1)(8)           |                                                                                      |                         
|EBITDA Reconciliation(9): |                                                                              |                                                                                      |                         
|                          | Net income (loss)                                                            |                                                                                      | $                       
|                          |                                                                              | Cumulative effect of accounting change(6)                                            |                         
|                          |                                                                              | Income tax expense (benefit)                                                         |                         
|                          |                                                                              | Interest expense and amortization of deferred loan costs, net of amounts capitalized |                         
|                          |                                                                              | Interest income                                                                      |                         
|                          |                                                                              | Depletion, depreciation, amortization and accretion(6)                               |                         
|                          |                                                                              |                                                                                      |                         
|                          |                                                                              |                                                                                      |                         
|                          |                                                                              |                                                                                      |                         

41

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|
|

|                                             |  | As of December 31, |         
|-------------------------------------------- |  | ------------------ | --------
|
|
|Selected Cash Flow Data:                     |  |                    |         
|Net cash provided by operating activities    |  | $                  | 122,869 
|                                             |  |                    |         
|Net cash used in investing activities(1)     |  | $                  | (515,826
|                                             |  |                    |         
|Net cash provided by financing activities(1) |  | $                  | 398,039 
|                                             |  |                    |         
|Selected Balance Sheet Data:                 |  |                    |         
|Working capital(10)                          |  | $                  | 2,262   
|Property and equipment, net                  |  |                    | 717,290 
|Total assets                                 |  |                    | 774,505 
|Long-term debt, including current maturities |  |                    | 260,000 
|Stockholders' equity(1)(8)                   |  |                    | 434,776 

---

We do not pay cash dividends on our common stock, and have not in the periods presented above; therefore, they are not presented in the selected
financial data.

42

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ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is a review of our financial position and results of operations for the periods indicated. Our Consolidated Financial Statements and Supplementary
Information and the related notes thereto contain detailed information that should be referred to in conjunction with Management's Discussion and Analysis of Financial Condition and Results of
Operations ("MD&A").

GENERAL OVERVIEW

Edge Petroleum Corporation ("Edge", "we" or the "Company") is a Houston-based independent energy company that focuses its exploration, development, production,
acquisition and marketing activities in selected onshore basins of the United States. In late 1998, we undertook a top-level management change and began a shift in strategy from pure
exploration, which focused more on prospect generation, to our current strategy which focuses on a balanced program of exploration, exploitation and development and acquisition of oil and gas
properties. We generate revenues, income and cash flows by producing and marketing oil and natural gas produced from our oil and natural gas properties. We make significant capital expenditures in our
exploration, development, and production activities that allow us to continue generating revenue, income and cash flows. We have also spent considerable efforts on acquisitions, including both
corporate and asset acquisitions, which have contributed to our growth in recent years.

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



INDUSTRY AND ECONOMIC FACTORS

In managing our business, we must deal with many factors inherent in our industry. First and foremost is the fluctuation of oil and natural gas prices.
Historically, oil and natural gas markets have been cyclical and volatile, which makes future price movements difficult to predict. While our revenues

43

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are
a function of both production and prices, wide swings in commodity prices have most often had the greatest impact on our results of operations. We have little ability to predict those prices or to
control them without losing some advantage of the upside potential.

Although
certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and
accelerated during 2005 and 2006, commodity prices for oil and natural gas increased significantly. The higher prices have led to increased activity in the industry and, consequently, rising costs.
These cost trends have put pressure not only on our operating costs but also on our capital costs for 2007. We expect this to be a factor in 2008.

Our
operations entail significant complexities. Advanced technologies requiring highly trained personnel are utilized in both exploration and production. Even when the technology is
properly used, we may still not know conclusively if hydrocarbons will be present or the rate at which they will be produced. Exploration is a high-risk activity, often times resulting in
no commercially productive reserves being discovered. These factors, together with increased demand for rigs, equipment, supplies and services, have made it difficult at times for us to further our
growth, and made timely execution of our planned activities difficult.

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

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

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

APPROACH TO THE BUSINESS

Profitable growth of our business will largely depend upon our ability to successfully find and develop new proved reserves of oil and natural gas in a
cost-effective manner. In order to achieve an overall acceptable rate of growth, we seek to maintain a prudent blend of low-, moderate- and higher-risk exploration
and development projects. We have chosen to seek geologic and geographic diversification by operating in multiple basins in order to mitigate risk in our operations. We also attempt to make selected
acquisitions of oil and natural gas properties to augment our growth and provide future drilling opportunities. In January 2007, we completed the acquisition of certain oil and natural gas
properties from a privately held company, as discussed below in "ACQUISITIONS AND DIVESTITURESAcquisitions." This was our largest
acquisition to date, and we spent much of 2007 integrating those assets into our business.

We
periodically hedge our exposure to volatile oil and natural gas prices on a portion of our expected production to reduce price risk. In 2007, we had 78% and 79% of our natural gas and
crude oil production, respectively, hedged. As a result of changes to our forecasted 2008 production and the impact of certain asset divestitures, both of which have reduced expected production as
compared to that expected at the time we entered into the derivative contracts, we currently have approximately 110% and 150% of our anticipated 2008 natural gas and crude oil production,
respectively, covered by derivative contracts. This overhedged position exposes us to greater risk of commodity price increases

44

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because
we will not have the physical production cash inflows to offset any potential losses incurred on the portion of the contracts that are overhedged.

Implementation
of our business approach relies on our ability to fund ongoing exploration and development projects with cash flow provided by operating activities and external sources of
capital. As a result of the ongoing strategic assessment process, our Board has approved an interim capital expenditure budget for 2008 of approximately $50 to $60 million, while we continue to
assess the potential sale or merger of the Company. Based on current expectations for production volumes and commodity prices, we expect to fund those capital expenditures from internally generated
cash from operating activities supplemented by modest borrowings on our credit facility. Any decision to expand our drilling program will depend in large part on the developments and results of our
strategic
assessment process that is currently underway (see "Outlook" section below). As of March 11, 2008, we have unused borrowing capacity of $50 million.

ACQUISITIONS AND DIVESTITURES

AcquisitionsWe have become increasingly active in acquisitions in recent years. We have looked to acquisitions to enable us
to achieve our growth objectives. Acquisitions add meaningful incremental increases in reserves and production and may range in size from acquiring a working interest in non-operated
producing property to an entire field or company. Unlike drilling capital, which is planned and budgeted, acquisition capital is neither budgeted nor allocated. Specific timing and size of
acquisitions cannot be predicted. Any such acquisition could involve the payment by us of a substantial amount of cash or the issuance of a substantial number of additional shares or other securities.
In today's high-price environment, where production is providing greater cash flow and earnings to most companies in our industry, identifying quality opportunities is difficult.

January 2007 AcquisitionDuring the first quarter of 2007, we completed the largest
acquisition in our history. We acquired oil and natural gas properties located in 13 counties in south and southeast Texas, exploration rights, leasehold acreage, gathering facilities and gathering
pipelines from a privately held company (the "January 2007 Acquisition"). The acquired assets include approximately 150 gross (74 net) producing wells and an ownership interest in
approximately 17,000 gross (12,250 net) developed acres and 56,000 gross (16,000 net) undeveloped acres of leasehold, all as of December 31, 2006. In addition to the
properties and related acreage, we acquired certain gathering facilities and ownership of approximately 13 miles of natural gas gathering pipelines and related infrastructure serving certain
producing assets in southeast Texas. The pipeline system transports our natural gas as well as third-party natural gas. We also acquired 25% of the seller's option and leasehold rights in an
approximate 95 square mile 3-D exploration area with approximately 30,000 gross acres of leases and options located in the Mission project area in Hidalgo County in south Texas, with a
primary focus on the Vicksburg formation. We acquired a 12.5% working interest in an approximate 160 square mile 3-D exploration area with approximately 55,000 gross acres of leases
and options located in the Yates Ranch/Hostetter project area in McMullen and Duval Counties in south Texas. The 160 mile 3-D area increases our exposure to the Middle and Deep
Wilcox trend. Furthermore, this venture allows us to participate in a proposed additional 3-D shoot covering approximately 120 square miles near the Yates Ranch within the Wilcox trend. We
also acquired 25% of the seller's option and leasehold rights in an approximate 105 square mile 3-D exploration area with approximately 60,000 gross acres of leases and options in Newton
County in southeast Texas and Beauregard Parish in Louisiana with a focus on prospects in the Frio, Yegua and Wilcox formations at depths ranging between 4,000 and 10,000 feet. The final adjusted cash
purchase price was $384.4 million. Pursuant to closing adjustment provisions in the agreements, the base purchase price was subject to adjustment for the results of operations between the
January 1, 2007 effective date and the January 31, 2007 closing date. We financed the purchase price of the January 2007 Acquisition through public offerings of common and
preferred stock (see Notes 11 and 12 to our consolidated financial statements) and borrowings under our credit facility (see

45

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Note 10
to our consolidated financial statements). We also capitalized approximately $1.4 million in other direct costs resulting from the acquisition and assumed ARO liabilities of
$0.9 million. The properties acquired are located in south and southeast Texas, which we consider to be our main core area of operations. This acquisition had a substantial impact on our
reserves, production revenues, operating costs, and property base. We have increased staffing levels to manage the growth and help with the integration of these assets into our operations.

During
the third quarter 2007, we elected to terminate the exploration venture located in the Yates Ranch/Hostetter project area in McMullen and Duval Counties in south Texas, which was
entered into in January 2007 (as discussed above and in Note 6 to our consolidated financial statements). The effective date of termination for this venture was October 2, 2007.
In exchange for returning all 3-D seismic data covering the area of mutual interest, the privately held company refunded our payments since January 2007 related to this exploration
venture. In October 2007, we received $5.5 million, including the $5.0 million initial price paid for the venture and $0.5 million in expenses related to the Venture, which
were incurred and paid to the privately held company from January to September 2007.

Chapman Ranch Acquisition 2006On December 12, 2006, we executed an agreement to acquire
certain working interests in the Chapman Ranch Field in Nueces County, Texas from
Kerr-McGee Oil & Gas Onshore LP ("Kerr-McGee"), a wholly-owned subsidiary of Anadarko Petroleum Corporation. In late 2005, we acquired non-operated
working interests in certain wells in this field. Upon the closing of the Kerr-McGee acquisition on December 28, 2006, we assumed the role of operator of the Chapman Ranch Field.
The final adjusted purchase price was approximately $25.3 million (including a previously paid deposit of $2.6 million) as a result of adjustments for the results of operations between
the December 1, 2006 effective date and the December 28, 2006 closing date, and other purchase price adjustments. We financed the purchase price of the Kerr-McGee acquisition
through $24.0 million in borrowings under our then-existing credit facility.

Chapman Ranch Acquisitions 2005During 2005, we acquired (i) the stock of a private
company, Cinco Energy Corporation ("Cinco"), whose primary asset is ownership of working interests in oil and natural gas properties located on the Chapman Ranch Field in south Texas (closed
November 30, 2005) and (ii) additional working interests in the same field owned by two other private companies (closed October 13, 2005) for an aggregate cash purchase price of
approximately $74.9 million (of which $46.9 million was attributable to the stock purchase and $28.0 million was attributable to the working interest asset purchase). We allocated
approximately $17.5 million of the total purchase price to the unproved property category. The properties acquired from these entities are located in Nueces County, Texas and consisted of six
producing wells, one well undergoing completion operations, and one well shut in for evaluation, as well as an ownership interest in approximately 1,300 net acres of developed and undeveloped
leasehold. We financed the acquisitions through borrowings under our then-existing credit facility.

DivestituresWe regularly review our asset base for the purpose of identifying non-core assets, the disposition of
which would increase capital resources available for other activities and create organizational and operational efficiencies. While we generally do not dispose of assets solely for the purpose of
reducing debt, such dispositions can have the result of furthering our objective of financial flexibility through reduced debt levels. During the first quarter of 2008, we expect to complete the sale
of a small group of non-core assets located in various areas of Texas for an anticipated sale price of approximately $16.4 million. During January 2007, we divested a portion
of our interest in a Louisiana well for $1.1 million. During 2006, we sold our Buckeye properties in Live Oak County, Texas for $0.6 million. During 2005, we had no divestitures.

46

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ASSESSMENT OF STRATEGIC ALTERNATIVES

On December 18, 2007, we announced the hiring of a financial advisor to assist our Board of Directors with an assessment of strategic alternatives. On
February 7, 2008, we provided an update on the strategic assessment process, which includes a thorough review and assessment of our strengths and weaknesses, competitive position and asset
base, reporting that after careful analysis, management and
our Board of Directors believed that the best route to maximizing stockholder value at that time was to focus on an assessment of a potential merger or sale of Edge. We are working diligently to
explore this alternative. A decision on any particular course of action has not been made and there can be no assurance that our Board of Directors will authorize any transaction. While that process
is continuing, we intend to operate Edge in a manner designed to capture the most value possible for our stockholders.

OUTLOOK



Our
outlook and the expected results described above are both subject to change based upon factors that include, but are not limited to, drilling results, commodity prices, the results
of our strategic assessment process, access to capital, the acquisitions market and factors referred to in "FORWARD LOOKING INFORMATION."

47

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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



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

Nature of Critical Estimate Item:Oil and Natural Gas ReservesOur estimate of
proved reserves is based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under
existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example,
we must estimate the amount and timing of future operating costs, severance taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition,
as prices and cost levels change from year to year, the economics of producing the reserves may change and therefore the estimate of proved reserves also may change. Any significant variance in these
assumptions could
materially affect the estimated quantity and value of our reserves. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements.

Assumptions/Approach Used:Units-of-production method to amortize our oil and natural
gas propertiesThe quantity of reserves could significantly impact our depletion expense. Any reduction in proved reserves without a corresponding reduction in capitalized
costs will increase the depletion rate.



48

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



---

Nature of Critical Estimate Item:Asset Retirement ObligationsWe have certain
obligations to remove tangible equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning
wells. Prior to the adoption of Statement of Financial Accounting Standards ("SFAS") No. 143,Accounting for Asset Retirement Obligations, the
costs associated with this activity were capitalized to the full-cost pool and charged to income through depletion. SFAS No. 143 significantly changed the method of accruing for
costs an entity is legally obligated to incur related to the retirement of fixed assets ("asset retirement obligations" or "ARO"). Primarily, SFAS No. 143 requires us to estimate asset
retirement costs for all of our assets, adjust those costs for inflation to the forecast abandonment date, discount that amount using a credit-adjusted-risk-free rate back to
the date we acquired the asset or obligation to retire the asset, and record an ARO liability in that amount with a corresponding addition to our asset value. When new obligations are incurred,
i.e. new well drilled or acquired, we add a layer to the ARO liability. We accrete the liability layers quarterly using the applicable period-end effective
credit-adjusted-risk-free rates for each layer. Should either the estimated life or the estimated abandonment costs of a property change upon our quarterly review, a new
calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our
credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to
the asset retirement cost (included in the full-cost pool); therefore, abandonment costs will almost always approximate the estimate. When well obligations are relieved by sale of the
property or plugging and abandoning the well, the related liability and asset costs are removed from our balance sheet.

Assumptions/Approach Used:Estimating the future asset removal costs is difficult and requires management to make estimates
and judgments because most of the removal obligations are many years in the future, and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies
and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the estimate of the present value calculation of our AROs are
numerous assumptions and judgments including the ultimate settlement

49

---



amounts,
inflation factors, credit-adjusted-risk-free-rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments.

Effect if different assumptions used:Since there are so many variables in estimating AROs, we attempt to limit the impact of
management's judgment on certain of these variables by using input of qualified third parties. We engage independent engineering firms to evaluate our properties annually. We use the remaining
estimated useful life from the year-end reserve reports by our independent reserve engineers in estimating when abandonment could be expected for each property. We utilize a
three-year average rate for inflation to diminish any significant volatility that may be present in the short term. We expect to see our calculations impacted significantly if interest
rates are volatile, as the credit-adjusted-risk-free rate is one of the variables used on a quarterly basis. We have developed a standard cost estimate based on historical
costs, industry quotes and depth of wells. Unless we expect a well's plugging to be significantly different than a normal abandonment, we use this estimate. The resulting estimate, after application
of a discount factor and some significant calculations, could differ from actual results, despite all our efforts to make an accurate estimate.

---

Nature of Critical Estimate Item:Income TaxesIn accordance with SFAS
No. 109,Accounting for Income Taxes,we have recorded a deferred tax asset and liability to account for the expected future tax benefits and
consequences of events that have been recognized in our financial statements and our tax returns. There are several items that result in deferred tax asset and liability impact to the balance sheet,
but the largest of which are income taxes and the impact of net operating loss ("NOL") carryforwards. We routinely assess our ability to use all of our NOL carryforwards that resulted
from substantial income tax deductions, prior year losses and acquisitions. We consider future taxable income in making such assessments. If we conclude that it is more likely than not that some
portion or all of the deferred tax assets will not be realized under accounting standards, it is reduced by a valuation allowance to remove the benefit of those NOL carryforwards from our financial
statements. Additionally, in accordance with Financial Accounting Standards Board ("FASB") Interpretation 48,Accounting for Uncertainty in Income Taxes, an Interpretation of
FASB Statement No. 109("FIN 48") we have recorded a liability of $0.5 million associated with uncertain tax positions. FIN 48 prescribes a
recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We are required to determine
whether it is more likely than not (a likelihood of more than 50 percent) that a tax position will be sustained upon examination, including resolution of any related appeals or litigation
processes, based on the technical merits of the position in order to record any financial statement benefit. If that step is satisfied, then we must measure the tax position to determine the amount of
benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate
settlement.

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

Effect if Different Assumptions Used:Our in-house tax department, along with consultation from an independent
public accounting firm used in tax consultation, continually evaluate complicated tax law requirements and their effect on our current and future tax liability and our tax filing positions. Despite
our attempt to make an accurate estimate, the ultimate utilization of our NOL carryforwards is highly dependent upon our actual production, the realization of taxable income in future periods,
Internal Revenue Code Section 382 limitations, and potential tax elections. If we estimate that some or all of our NOL carryforwards are more likely than not going to expire or otherwise not be
utilized to reduce future tax, we would record a valuation allowance to remove the benefit of those NOL

50

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carryforwards
from our financial statements. Our liability for uncertain tax positions is dependent upon our judgment on the amount of financial statement benefit that an uncertain tax position will
realize upon ultimate settlement and on the probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information
available at the reporting date to establish the appropriate amount of financial statement benefit. To the extent that a valuation allowance or uncertain tax position is established or increased or
decreased during a period, we may be required to include an expense or benefit within tax expense in the income statement.

---

Nature of Critical Estimate Item:Derivative and Hedging ActivitiesDue to the
instability of oil and natural gas prices, we may enter into, from time to time, price-risk management transactions (e.g., swaps, collars and floors) related to our expected oil and
natural gas production to seek to achieve a more predictable revenue, as well as to reduce exposure from commodity price fluctuations. While these transactions are intended to be economic hedges of
price risk, different accounting treatment may apply depending on if they qualify for cash flow hedge accounting. In accordance with SFAS No. 133,Accounting for
Derivative Instruments and Hedging Activities (as amended),all derivatives, other than those that meet the normal purchases and sales exception, are recorded on the balance
sheet at fair value. SeeITEMS 1 AND 2. "BUSINESS AND PROPERTIESDERIVATIVES."



Assumptions/Approach Used:Estimating the fair values of derivative instruments requires complex calculations, including the
use of a discounted cash flow technique, estimates of risk and volatility, and subjective judgment in selecting an appropriate discount rate. In addition, the calculations use future market commodity
prices, which although posted for trading purposes, are merely the market consensus of forecasted price trends. The results of the fair value calculations cannot be expected to represent exactly the
fair value of our commodity hedges. We currently obtain the fair value of our positions from our counterparties. Our practice of relying on our counterparties who are more specialized and
knowledgeable in preparing these complex calculations reduces our management's input and approximates the fair value of the contracts, as the fair value obtained from our counterparties would be the
cost to us to terminate a contract at that point in time. Due to the fact that we apply mark-to-market accounting treatment, the offset to the balance sheet asset or liability,
or the change in fair value of the contracts, is included in revenue on the income statement rather than in OCI on the balance sheet.

51

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Effect if different assumptions used:At December 31, 2007, a 10% change in the commodity price per unit, as long as
the price is either above the ceiling or below the floor price, would cause the fair value total of our derivative financial instruments to increase or decrease by approximately $1.7 million.
Had we applied cash flow hedge accounting treatment to all of our derivative contracts outstanding at December 31, 2007, our net income available to common stockholders for the year would have
been $10.2 million.

RESULTS OF OPERATIONS

This section includes discussion of our 2007, 2006 and 2005 results of operations. We are an independent oil and natural gas company engaged in the exploration,
development, acquisition and production of crude oil and natural gas properties in the United States. Our resources and assets are managed and our results reported as one operating segment. We conduct
our operations primarily along the onshore United States Gulf Coast, with our primary emphasis in Texas, Mississippi, New Mexico and Louisiana.

Revenue and Production

Our primary source of production and revenue is natural gas. For the years ended December 31, 2007, 2006 and 2005, our product mix contributed the
following percentages of revenues and production:

REVENUES(1)

2007

2006

2005Natural gas

74
%
79
%
82
%Natural gas liquids

16
%
4
%
5
%Crude oil

10
%
17
%
13
%Total

100
%
100
%
100
%




PRODUCTION VOLUMES (MCFE)

2007

2006

2005Natural gas

73
%
80
%
77
%Natural gas liquids

16
%
8
%
11
%Crude oil

11
%
12
%
12
%Total

100
%
100
%
100
%


Our
revenue is sensitive to changes in prices received for our products. A substantial portion of our production is sold at prevailing market prices, which fluctuate in response to many
factors that are outside of our control. Imbalances in the supply and demand for oil and natural gas can have a dramatic effect on the prices we receive for our production. Political instability and
availability of alternative fuels could impact worldwide supply, while the economy, weather and other factors outside of our control could impact demand.

52

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The
following table summarizes production volumes, average sales prices and operating revenue for our oil and natural gas operations for the periods indicated.

|                                          |  | For the Year Ended December 31, |         | % Increase
(Decrease) |  
|----------------------------------------- |  | ------------------------------- | ------- | --------------------- | -
|
|
|Production Volumes:                       |  |                                 |         |                       |  
|Natural gas (MMcf)                        |  |                                 | 17,536  |                       |  
|Natural gas liquids (MBbls)               |  |                                 | 637     |                       |  
|Oil and condensate (MBbls)                |  |                                 | 460     |                       |  
|Natural gas equivalent (MMcfe)            |  |                                 | 24,118  |                       |  
|Average Sales Price (1):                  |  |                                 |         |                       |  
|Natural gas ($ per Mcf)(2)                |  | $                               | 6.66    |                       | $
|Natural gas liquids ($ per Bbl)           |  |                                 | 40.00   |                       |  
|Oil and condensate ($ per Bbl)(2)         |  |                                 | 70.86   |                       |  
|Natural gas equivalent ($ per Mcfe)(3)    |  |                                 | 6.67    |                       |  
|Operating Revenue:                        |  |                                 |         |                       |  
|Natural gas(2)                            |  | $                               | 116,777 |                       | $
|Natural gas liquids                       |  |                                 | 25,489  |                       |  
|Oil and condensate(2)                     |  |                                 | 32,572  |                       |  
|Gain (loss) on hedging and derivatives(4) |  |                                 | (13,938 | )                     |  
|                                          |  |                                 |         |                       |  
|Total(3)                                  |  | $                               | 160,900 |                       | $
|                                          |  |                                 |         |                       |  

---

*Not
meaningful.

Natural gas revenueThe overall increase in production for 2007 compared to 2006 resulted in an
increase in revenue of approximately $24.6 million (based on 2006 comparable period pre-derivative prices). Average prices received in 2007 were slightly lower than 2006, resulting
in decreased revenue of approximately $0.4 million (based on current period production). The overall increase in production for 2006 compared to 2005 resulted in an increase in revenue of
approximately $10.0 million (based on 2005 comparable period pre-hedge/derivative prices). Excluding the effect of hedge and derivative activity, the average natural gas sales price
for production in 2006 was lower than 2005, which resulted in decreased revenue of approximately $17.8 million (based on 2006 production). Average natural gas production increased from 34.5
MMcf/d in 2005 and to 37.9 MMcf/d in 2006 to 48.0 MMcf/d in 2007. The growth in natural gas production in 2007 was primarily due to the addition of new assets acquired in the January 2007 Acquisition
and to a lesser extent the additional assets acquired in the Chapman Ranch Field in December of 2006. Additionally, new wells drilled in the Vicksburg and Deep Frio project areas of Texas and in
southeast New Mexico contributed to the growth. Partially offsetting these increases were declines in Mississippi, some of our Queen City and Lobo properties in Texas, and on older wells in the
southeast New Mexico project area. Production increases in 2006 as compared to 2005 were attributable to significant drilling at our Queen City and southeast New Mexico properties, as well as
acquisitions, including the Chapman Ranch Field in late 2005 and additional working interests in the Chapman Ranch Field in December of 2006, for which the impact was more noticeable

53

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in
2007. Partially offsetting the increases in production in 2006 as compared to 2005 were natural declines in production in our older properties including Gato Creek, Encinitas and Miller.

NGL revenueRevenue from the sale of NGLs remained flat for the year ended December 31,
2006 over the same period in 2005, but increased significantly for the year ended December 31, 2007. Average realized prices have increased, which positively impacted revenues. The substantial
increase in production in 2007 is partially attributable to the January 2007 Acquisition. In late 2006 and early 2007, we entered into natural gas processing agreements for our Chapman Ranch
production and our non-operated Queen City production in Jim Hogg County, which agreements contributed a portion of the increase in NGL production in 2007 as compared to 2006. The decrease
in production from 2005 to 2006 is mainly attributed to natural production declines at our Encinitas, Gato Creek and Louisiana properties.

Crude oil and condensate revenueRevenue from the sale of oil and condensate, excluding
derivative activity, has steadily increased from 2005 to 2006 and 2006 to 2007 as a result of both increases in production and average realized prices. Crude oil prices have increased in the
marketplace and we have realized the benefit of those increases in our unhedged revenue. Production volumes for oil and condensate increased to 1,259 Bbls/d for the year ended December 31, 2007
from 945 Bbls/d for the same period in 2006 and from 887 Bbls/d for the same period in 2005. The growth in crude oil and condensate in 2007 was primarily due to the addition of new assets acquired in
the January 2007 Acquisition and to a lesser extent the additional assets acquired in the Chapman Ranch Field in December of 2006. Additionally, new wells in the Vicksburg, Deep Frio and southeast New
Mexico project areas contributed to the growth. Partially offsetting these increases were declines in Mississippi, some of our Queen City and Lobo properties in Texas, and on older wells in the
southeast New Mexico project area. The increase in 2006 as compared to 2005 was from production on new wells drilled in our Queen City and southeast New Mexico projects, as well as from the Chapman
Ranch Field properties acquired in late 2005, partially offset by declines in production from our Miller, Encinitas, and Gato Creek properties.

DerivativesOur hedging and derivative contracts resulted in a net loss in 2007 and 2005 and a
net gain in 2006. During the first quarter of 2006, we discontinued cash flow hedge accounting treatment applied to our natural gas collars. This change in accounting treatment affects the
comparability of the periods (see Note 9 to our consolidated financial statements) because the change in fair market value of the natural gas hedge contracts in 2005 was deferred through OCI on
the balance sheet rather than presented in total revenue on the income statement, as presented in 2007 and 2006. The volume and price contract terms vary from period to period and therefore interact
differently with the changing pricing environment. While we are unable to predict the market prices, we enter into contracts that we expect will protect us in the event of significant downturns in the
market, which has proven to be a benefit to us in 2007 and 2006 for natural gas. Natural gas prices declined in relation to our derivative contracts in place, resulting in cash settlement inflows from
our hedge counterparties to offset the lower prices received for our physical production. The opposite was true of our crude oil derivative contracts in 2007 and 2005. The following table summarizes
the various

54

---



components
of the total gain or loss on hedging and derivatives for each of the periods indicated and the impact each component had on our realized prices:

|                                                                                                          |                                               | Year Ended December 31, |        
|--------------------------------------------------------------------------------------------------------- | --------------------------------------------- | ----------------------- | -------
|
|
|
|Natural gas contract settlements (Mcf)                                                                    |                                               | $                       | 4,513  
|Crude oil contract settlements (Bbl)                                                                      |                                               |                         | (935   
|Mark-to-market reversal of prior period unrealized change in fair value of gas derivative contracts (Mcf) |                                               |                         | (4,686 
|Mark-to-market unrealized change in fair value of gas derivative contracts (Mcf)                          |                                               |                         | 2,626  
|Mark-to-market reversal of prior period unrealized change in fair value of oil derivative contracts (Bbl) |                                               |                         | (500   
|Mark-to-market unrealized change in fair value of oil derivative contracts (Bbl)                          |                                               |                         | (14,956
|                                                                                                          |                                               |                         |        
|                                                                                                          | Gain (loss) on hedging and derivatives (Mcfe) |                         | $      
|                                                                                                          |                                               |                         |        

Should crude oil or natural gas prices increase or decrease from the current levels, it could materially impact our revenues. Our physical sales
of these commodities are vulnerable to the volatility of market price movements. Therefore, we enter into contracts covering our anticipated production to ensure certain revenues that we expect will
allow us to plan our business activities. In a high price environment, hedged positions could result in lost opportunities if there is a ceiling in place, thus lowering our effective realized prices
on hedged production, but in an environment of falling prices, these transactions offer some pricing protection for hedged production. Our current derivative position exceeds our 2008 expected
production, therefore we could incur realized cash losses if oil and natural gas commodity prices increase significantly during 2008, see "Approach to the Business" above.

55

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Costs and Operating Expenses

The table below presents a detail of expenses for the periods indicated:

|                                                     |                                            | December 31, |         | % Increase (Decrease) |  
|---------------------------------------------------- | ------------------------------------------ | ------------ | ------- | --------------------- | -
|
|
|Oil and natural gas operating expenses               |                                            | $            | 17,078  |                       | $
|Severance and ad valorem taxes                       |                                            |              | 13,118  |                       |  
|Depreciation, depletion, amortization and accretion: |                                            |              |         |                       |  
|                                                     | Oil and natural gas property and equipment |              |         | 90,826                |  
|                                                     | Other assets                               |              |         | 595                   |  
|                                                     | ARO accretion                              |              |         | 297                   |  
|Impairment of oil and natural gas properties         |                                            |              |        |                       |  
|General and administrative expenses:                 |                                            |              |         |                       |  
|                                                     | Bad debt expense                           |              |         | 257                   |  
|                                                     | General and administrative expenses        |              |         | 17,237                |  
|                                                     |                                            |              |         |                       |  
|Total operating expenses                             |                                            | $            | 139,408 |                       | $
|                                                     |                                            |              |         |                       |  
|Other expense, net                                   |                                            | $            | 11,187  |                       | $
|Income tax expense (benefit)                         |                                            |              | 3,733   |                       |  
|Preferred stock dividends                            |                                            |              | 7,577   |                       |  

---

Oil and natural gas operating expensesOil and natural gas operating expenses in 2007 were
significantly impacted by the January 2007 Acquisition, which contributed 70% of the increase in costs (averaging $0.58 per Mcfe for the year) from 2006 to 2007. The increasing cost structure
in 2007 as compared to 2006 resulted from added costs for compression, expensed workovers and salt-water disposal as well as inflation in our industry. The increase in expenses was also
affected to a lesser extent by the Chapman Ranch acquisition in December of 2006. The 2006 results were impacted by increased costs on our States, Gato Creek and southeast New Mexico properties. We
also experienced increases in 2006, as compared to 2005, due to the Chapman Ranch properties acquired late in 2005, but costs for this area were not as high as expected due to delays in our Chapman
Ranch drilling program during 2006. Operating expenses averaged $0.71 per Mcfe, $0.53 per Mcfe and $0.52 per Mcfe for the years ended December 31, 2007, 2006 and 2005, respectively.

Severance and ad valorem taxesSeverance taxes are levied directly on our non-hedge
revenue dollars, so the increasing trend is consistent with our increasing revenue. Partially offsetting the increase from revenues is a declining rate realized. The severance tax rate realized in the
years ended December 31, 2007, 2006 and 2005 was 4.8%, 5.4% and 5.7%, respectively. The rate realized changes as a result of the changing mix of our production locations. In recent years, we
have expanded our production to areas outside of Texas, which imposes a high tax rate of approximately 7.5% of the revenue dollar. Additionally, in 2007 and 2006, we received severance tax abatements
on certain Chapman Ranch Field locations acquired late in 2005 and 2006 as a result of these properties qualifying for high-cost gas certification, which lowered our overall severance tax
rate. Ad valorem costs have increased due to the addition of properties acquired in January 2007. If not for the January 2007 Acquisition, ad valorem tax expense would have decreased by
approximately 50% as compared to the year ended December 31, 2006. On an equivalent basis, severance and ad valorem taxes averaged $0.54

56

---



per
Mcfe, $0.53 per Mcfe and $0.52 per Mcfe for the years ended December 31, 2007, 2006 and 2005, respectively.

Depletion, depreciation and amortization ("DD&A") and accretion expenseFull-cost
depletion on our oil and natural gas properties has increased as a result of both rate and volume increases in recent years. Depletion expense on a unit of production basis for the years ended
December 31, 2007, 2006 and 2005 was $3.77 per Mcfe, $3.51 per Mcfe and $2.43 per Mcfe, respectively. The depletion rate has increased in recent years due to significant property costs for both
drilling and exploration activities as well as our acquisition program without a corresponding increase in reserves. Additionally, negative revisions to our proved reserves at year-end
2007 increased our depletion rate.

Depreciation
expense of other assets is related to our executive office furniture and fixtures, computer equipment and software and pipelines acquired in the January 2007
Acquisition that transport third-party gas. Depreciation expense related to other assets increased from 2006 to 2007 due to new assets needed for growth of our executive offices, including leasehold
improvements for our office expansion, new office furniture and equipment and computers and software. Our depreciation expense related to other assets increased from 2005 to 2006 because we fully
depreciated computer software programs during the year and then replaced those same programs with new, upgraded technology.

Accretion
expense on our ARO liability increased in 2007 and 2006 due to the addition of new obligations associated with wells added each year, including the large acquisition completed
in January 2007. Accretion expense is calculated using the interest method of allocation, which calculates interest on the cumulative balance such that the interest increases with each
subsequent period.

Impairment of oil and natural gas propertiesWe recorded a non-cash
full-cost ceiling test impairment of oil and natural gas properties in the amount of $96.9 million ($63.0 million, net of tax) during 2006 as a result of declines in natural
gas prices at September 30, 2006. No such impairment was recorded in 2007 or 2005.

Bad debt expenseDuring 2007, we recorded bad debt expense of $0.5 million related to the
ongoing Golden Prairie/Enron dispute that we no longer felt we could collect as we exhausted our efforts on this matter. This was partially offset by a reduction of bad debt expense of
$0.3 million for a receivable that was reserved as uncollectible in 2001, but recovered during the fourth quarter of 2007. During 2005, we recorded $65,157 of bad debt expense to increase our
allowance for outstanding receivables from joint interest owners. There was no bad debt expense recorded in 2006. Historically we have not experienced significant credit losses on our receivables, but
we cannot ensure that similar such losses may not be realized in the future.

General and administrative ("G&A") expensesThe majority of the increase in G&A expense over the
periods presented is the result of increasing our staffing levels. Our salary and benefits comprise approximately 80% of total G&A expense each year. We added 21 new employees during the year ended
December 31, 2007 and seven during the year ended December 31, 2006 as a result of our continued growth. A portion of the increase in G&A expense is attributable to stock-based
compensation costs related to restricted stock awards granted over the past three years, which has increased from $1.0 million in 2005 to $1.9 million in 2006 and to $3.0 million
in 2007. This gradual increase in compensation for restricted stock awards is related to additional restricted stock awards granted in conjunction with our increase in employees from 2005 to 2007 as
well as the vesting of additional tranches of grants already awarded to existing employees. Other cost increases during 2007 include rent expense for our corporate office expansion and professional
service fees, offset by decreased costs for our board of directors and franchise taxes. In 2006, we experienced higher legal fees in conjunction with increased legal activity in Texas and Louisiana.
Also in 2006, we paid a franchise tax settlement to the State of Texas of approximately $0.2 million and a litigation settlement.

57

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G&A
costs were partially offset by increased capitalized G&A and overhead reimbursement fees (which reduce total G&A costs). We capitalized $4.0 million, $3.0 million and
$2.6 million of general and administrative costs in 2007, 2006 and 2005, respectively. For the years ended December 31, 2007, 2006 and 2005, overhead reimbursement fees reduced G&A costs
by approximately $1.2 million, $0.4 million, and $0.3 million, respectively. G&A expenses, excluding non-cash share-based compensation costs, on a unit of production
basis for the years ended December 31, 2007, 2006 and 2005 were $0.60 per Mcfe, $0.68 per Mcfe and $0.60 per Mcfe, respectively.

Upon
adoption of SFAS No. 123(R), as discussed in Notes 2 and 18 to our consolidated financial statements, during 2006, we recorded $68,937 in compensation expense for
stock options that had not vested as of adoption of SFAS No. 123(R). Those options have since vested and we have not issued new options since 2004. Therefore, we did not record any stock option
expense in 2007 nor do we expect to record expense related to stock options in the near future.

In
2006, in conjunction with the adoption of SFAS No. 123(R), we discontinued the application of FIN 44 accounting treatment for repriced options and began recording
compensation expense for stock options that had not vested as of the date of adoption of SFAS No. 123(R). Prior to 2006, FIN 44 accounting treatment was applied to our repriced options,
which calls for a non-cash charge to compensation expense if the price of our common stock on the last trading day of a reporting period is greater than the exercise price of certain
repriced options. FIN 44 could also result in a credit to compensation expense to the extent that the trading price declines from the trading price as of the end of the prior period, but not
below the exercise price of the options. Pre-2006, we adjusted compensation expense upward or downward monthly based on the trading price at the end of each such period. We were required
to report under this rule as a result of non-qualified stock options granted to employees and directors in prior years and repriced in May of 1999, as well as certain newly issued options
in conjunction with the repricing. A FIN 44 charge on our repriced stock options was required in 2005 as a result of our stock price exceeding the exercise price of those repriced options. The
average price at December 31, 2005 that was used to calculate this expense was $24.65 per share. In conjunction with the adoption of SFAS No. 123(R) on January 1, 2006, we
discontinued the application of FIN 44, and hence there will not be any additional adjustments for charges or credits to compensation expense related to repriced options.

Other income (expense)For the years ended December 31, 2007 and 2006, we only capitalized
a portion of our interest expense. But in the year ended December 31, 2005, we capitalized 100% of our interest expense because our unproved property balance exceeded our weighted average debt
balance. At December 31, 2007, 2006 and 2005 our unproved property balance was $34.9 million, $57.6 million, and $36.9 million, respectively. We incurred higher gross
interest costs for the year ended December 31, 2007 than for 2006 and 2005 due to higher commitment fees on our credit facility and higher outstanding debt balances, as well as a one time
commitment fee of $1.3 million paid to our lender for the unused bridge loan facility in January 2007 (see Note 10 to our consolidated financial statements). The year ended
December 31, 2006 also includes interest paid on our franchise tax settlement in 2006 of approximately $40,150. Interest costs on the franchise tax settlement were not subject to
capitalization. The table below details our interest expense, capitalized interest and weighted average debt for each of the periods indicated:

For the Year Ended December 31,2007

2006

2005(in thousands)Gross interest

$
18,471

$
7,761

$
1,943Less: capitalized interest


(7,882
)

(5,261
)

(1,943
)Interest expense, net

$
10,589

$
2,500

$
Weighted Average Debt

$
229,597

$
102,077

$
24,189


58

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Included
in other income (expense) is amortization of deferred loan costs of $1.0 million associated with our credit facility for the year ended December 31, 2007 and
$0.2 million associated with our then-existing credit facility for the years ended December 31, 2006 and 2005. These costs were higher in 2007 due to the higher costs
associated with our current credit facility compared to our prior credit facility.

Also
included in other income (expense) was interest income, which totaled $0.4 million, $0.2 million, and $0.1 million for the years ended December 31, 2007,
2006 and 2005, respectively. The interest is earned on daily cash invested in overnight money market funds. We have had increased cash on hand in recent years providing for the increased interest
income.

Income tax expense/benefitWe are subject to state and federal income taxes and although we were
recently generating taxable income for financial reporting purposes, we are not in a federal income tax paying position as a result of deducting intangible drilling costs ("IDC") that reduce our
taxable income for income tax purposes and NOL carryforwards that offset any remaining taxable income. A deferred income tax provision of $3.7 million was recorded for the year ended
December 31, 2007. A deferred income tax benefit of $21.6 million and a provision of $18.1 million were recorded for the years ended December 31, 2006 and 2005,
respectively. Due to changes in amounts of permanent tax differences, including meals and entertainment and other expenses, our effective tax rate also changes from time to time. The effective rate
was 36.2% for the year ended December 31, 2007, as compared to 34.3% in 2006 and 35.2% in 2005. As of December 31, 2007, approximately $146.5 million of net operating loss
carryforwards have been accumulated or acquired that will begin to expire in 2012. We were required to make alternative minimum tax payments of $94,100 and $327,400 for the years ended
December 31, 2006 and 2005, respectively, but do not expect any alternative minimum tax liability in 2007.

Preferred stock dividendsOur Board of Directors declared quarterly dividends on our 5.75%
Series A cumulative convertible perpetual preferred stock in 2007. The preferred stock was issued in connection with a public offering in January 2007, therefore no comparable dividends
were paid in 2006 or 2005.

Earnings/loss per shareFor the years ended December 31, 2007 and 2006, we reported a net
loss available to common shareholders as compared to net income available to common shareholders in the same period in 2005. Basic weighted average shares outstanding increased from approximately
17.1 million at December 31, 2005 to 17.4 million at December 31, 2006 and to 27.6 million at December 31, 2007. There were minimal increases due to options
exercised and vesting of restricted stock during each of these periods, but the primary cause of the significant increase from 2006 to 2007 was the public offering of common stock in
January 2007 that was made to partially finance the January 2007 Acquisition. We issued approximately 10.9 million shares of common stock. We also issued approximately
2.9 million shares of 5.75% Series A cumulative convertible perpetual preferred stock, which, when converted, have an anti-dilutive effect of approximately 8.7 million
shares of common stock, and therefore, are not included in the calculation of diluted earnings per share for the year ended December 31, 2007. Diluted earnings per share calculations in loss
periods do not include certain shares that would result in an anti-dilutive effect on earnings per share.

LIQUIDITY AND CAPITAL RESOURCES

Our primary ongoing source of capital is the cash flow generated from our operating activities supplemented by borrowings under our credit facility. Net cash
generated from operating activities is a function of production volumes and commodity prices, both of which are inherently volatile and unpredictable, as well as operating efficiency and costs. Our
business, as with other extractive businesses, is a depleting one in which each gas equivalent unit produced must be replaced or our asset base and capacity to generate revenues in the future will
shrink. Our overall expected future production

59

---



decline
is estimated to be approximately 25% per year. Less predictable than production declines from our proved reserves is the impact of constantly changing oil and natural gas prices on cash flows.
We attempt to mitigate the price risk with our hedging program. Reserves and production volumes are influenced, in part, by the amount of future capital expenditures. In turn, capital expenditures are
influenced by many factors including drilling results, oil and natural gas prices, industry conditions, prices, availability of goods and services and the extent to which oil and natural gas
properties are acquired.

Our
primary cash requirements are for exploration, development and acquisition of oil and natural gas properties, payment of preferred stock dividends and the repayment of principal and
interest on outstanding debt. We attempt to fund our exploration and development activities primarily through internally generated cash flows and budget capital expenditures based largely on projected
cash flows. We routinely adjust capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, and cash flow. We typically have funded acquisitions from
borrowings under our credit facility, cash flow from operations and sales of common stock and preferred stock.

Significant
changes to working capital may affect our liquidity in the short term. We now pay quarterly dividends on our preferred stock, which is a new and ongoing use of our cash. The
increase in our derivative instrument liability is indicative of potential future cash settlement outflows on our outstanding oil, and to a lesser extent natural gas, derivative positions, which are
scheduled to settle in future months. The fair market value represents the potential settlement for those contracts if the market prices remain unchanged, but should commodity prices increase or
decrease, the fair value of those outstanding contracts would change and the settlements at maturity would also change. When our derivatives result in cash settlement outflows, we receive higher cash
inflows on the sale of unhedged production at those higher market prices, thus providing us with additional funds with which to cover at least a portion of any derivative payments that may come due in
the future. This will not be true, however, for the portion of our 2008 production that is overhedged. Currently we expect to have 110% of our anticipated natural gas production and 150% of our
anticipated crude oil production hedged in 2008 as a result of a decrease in expected future production since the time we entered into our 2008 derivative positions. We have no derivatives covering
our substantial production of NGLs, which have historically received a price of approximately 50% of our realized crude oil price. As a result, even though we do not benefit from increases in oil
prices and might suffer increased losses as oil prices
increase, those increased losses may be partially offset by increases in our NGL revenues. See "Approach to the Business" above.

We
have historically used our credit facility to supplement any deficiencies between operating cash flow and capital expenditures. Our outstanding debt balance at March 11, 2008
was $250.0 million, primarily due to the funding of our acquisition program, principally the 2005 and 2006 acquisitions in the Chapman Ranch field and the January 2007 Acquisition. We
typically do not rely on the sale of assets as a source of cash, but will realize approximately $16.4 million related to the sale of several non-core assets during the first quarter
of 2008, and we expect to use the proceeds to reduce outstanding debt.

We
have reduced our planned capital spending for 2008 as compared to recent years. As a result of the ongoing strategic assessment process, our Board of Directors has approved an interim
capital budget. Initially that budget is expected to be approximately $50 to $60 million and is expected to be less than our cash flow from operating activities, thereby allowing us to reduce
outstanding debt as we move through the year.

During
2005 and 2007, we realized increased cash flows as a result of our public and private stock offerings. We have also realized cash flows from the exercises of options and warrants
to acquire shares of our common stock, although we typically do not rely on proceeds from the exercise of warrants and

60

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stock
options to sustain our business, as the timing of their exercise is unpredictable. At December 31, 2006 and 2007, we had certain options outstanding and exercisable for shares of our
common stock.

We
had cash and cash equivalents at December 31, 2007 of $7.2 million consisting primarily of short-term money market investments, as compared to
$2.1 million at December 31, 2006. Working capital was $2.3 million as of December 31, 2007, as compared to $10.2 million at December 31, 2006.

For the Year Ended December 31,2007

2006

2005(in thousands)Net Cash Provided By Operating Activities

$
122,869

$
97,409

$
93,111Net Cash Used In Investing Activities


(515,826
)

(140,412
)

(167,280
)Net Cash Provided by Financing Activities


398,039


44,418


72,568


Net Cash Provided By Operating ActivitiesThe significant increase in cash flows provided by
operating activities for the year ended December 31, 2007 compared to 2006 and 2005 was primarily due to the January 2007 Acquisition. The major source of funds was revenue of
$160.9 million, partially offset by cash operating expenses of $30.2 million and general and administrative expenses of $17.2 million. Contributing to the decrease in the level of
cash provided by operating activities in 2007 was the net timing effects of receipts of accounts receivable payments of accrued liabilities and accounts payables.

Net
cash generated from operating activities is a function of production and commodity prices, which are inherently volatile and unpredictable, and costs of operating our business and
properties. 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 cash settlement
gains of $4.5 million and $4.7 million on our natural gas derivatives during 2007 and 2006, respectively. Partially offsetting these cash inflows were cash settlement losses of
$0.9 million on our crude oil derivatives during 2007. During 2005, we recorded cash settlement losses on both natural gas and crude oil derivatives of $1.2 million and
$1.8 million, respectively. Overall, oil and gas production revenue, including the effects of derivatives and hedging, for 2007 increased 24% over 2006 and 33% over 2005.

Although
fluctuations in commodity prices have been the primary reason for our short-term changes in cash flow from operating activities, increased production volumes also
impacted us in 2007 and 2006. Our business, as with other extractive businesses, is a depleting one
in which each gas equivalent produced must be replaced or our asset base and capacity to generate revenues in the future will shrink. Our ability to prevent shrinkage will be affected in the future by
the successes and/or failures of our exploration, production and acquisition activities.

For
these reasons, we put in place an annual budget that is based upon our forecasts for production, revenues and costs. Those forecasts are reviewed and updated regularly by management
and our capital budget is adjusted as warranted.

In
the event such capital resources are not available to us, our drilling and other activities may be curtailed. SeeITEMS 1A. "RISK
FACTORSOur operations have significant capital requirements which, if not met will hinder operations."

Net Cash Used In Investing ActivitiesWe reinvest a substantial portion of our cash flows in our
drilling, acquisition, land and geophysical activities. As a result, we used $515.8 million in investing activities during 2007. Acquisition costs of $375.2 million were related to the
January 2007 Acquisition, which was the largest in our history. Capital expenditures of $113.2 million were attributable to the drilling of 50 gross wells, 46 of which were apparently
successful and 39 recompletions. Higher net capital costs per well in 2007 as compared to prior years were due to higher average working interests and higher gross costs per well in Arkansas and Deep
Frio project areas as compared to wells drilled in

61

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previous
years. General increases in costs of services as a result of higher commodity price environment also contributed. Other spending included $20.5 million attributable to land holdings,
capitalized G&A and interest and $6.0 million for seismic data and other geological and geophysical expenditures. The remaining capital expenditures were associated with computer hardware and
office furniture and equipment. We also received $1.1 million during early 2007 from the sale of a portion of our interest in a Louisiana well.

During
the year ended December 31, 2006, we used $140.4 million in investing activities. Capital expenditures of $82.6 million were attributable to the drilling of
52 gross wells, 43 of which were apparently successful. Acquisition costs totaled $39.4 million, mainly related to the acquisition of additional interests in the Chapman Ranch Field late in
2006 and final adjustments to the Cinco purchase price. Other spending included $14.0 million attributable to land holdings, capitalized G&A and interest and $7.7 million for increased
seismic data and other geological and geophysical expenditures. Drilling advances to the operator of our Queen City properties decreased in 2006 by approximately $2.9 million. We also received
$0.6 million during 2006 from the sale of our Buckeye properties. The remaining capital expenditures were 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 $79.1 million were attributable to the drilling of
65 gross wells, 62 of which were
apparently successful. Acquisition costs related to the private company corporate acquisition totaled $39.0 million, net of cash acquired, and other acquisition costs totaled
$28.0 million, mainly related to the Chapman Ranch Field asset acquisition. Other spending included $14.4 million attributable to land holdings, capitalized G&A and interest and
$2.5 million for increased seismic data and other geological and geophysical expenditures. Drilling advances to the operator of our Queen City properties amounted to $4.3 million during
2005. The remaining capital expenditures were associated with computer hardware, office furniture and equipment for the expansion into additional office space.

We
will be operating under an interim capital spending budget in 2008 while we continue to assess the potential sale or merger of the Company. This interim program, which could be
supplemented quickly, calls for the drilling of 18 to 22 wells (7 to 9, net) during 2008, primarily in south Texas, and to a lesser extent in southeast New Mexico, complemented by selected
expenditures for land and seismic. The interim program is estimated to have total capital spending in the range of $50 to $60 million.

Net Cash Provided By Financing ActivitiesCash flows provided by financing activities were significantly impacted by the
public offerings of common stock and preferred stock completed in January 2007. In connection with the newly issued preferred stock, we paid $5.9 million in dividends to preferred
shareholders during 2007. We also refinanced our prior credit facility borrowings of $129 million with our current credit facility, which we borrowed against to partially finance the
January 2007 Acquisition. In total, we had $275.0 million in borrowings and $144.0 million in repayments during 2007. In connection with our credit facility, we incurred loan
costs of approximately $3.7 million. In addition, we received approximately $42,100 in proceeds from the issuance of common stock related to options exercised in 2007.

During
the year ended December 31, 2006, cash flows provided by financing activities totaled $44.4 million. We had $62.0 million in borrowings and
$18.0 million in repayments under our prior credit facility. We incurred loan costs of approximately $0.2 million in amending our prior credit facility. In addition, we received
$0.6 million in proceeds from the issuance of common stock related to options exercised in 2006.

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

Credit Facility

On December 21, 2006, we amended our Third Amended and Restated Credit Agreement (the "Prior Credit Facility"), which we had originally entered into in
March 2004 (effective December 31, 2003) and previously amended on December 4, 2006. The Prior Credit Facility permitted borrowings up to the lesser of (i) the borrowing
base and (ii) $150.0 million. Effective December 2006, the borrowing base under the Prior Credit Facility was increased from $125.0 million to $140.0 million as a
result of acquisitions and our drilling activities since the last redetermination. Based on the increase, our available borrowing capacity at December 31, 2006 was $11.0 million.

The
Prior Credit Facility's scheduled maturity date was March 31, 2008, and it was secured by substantially all of our assets. As discussed in Note 10 to our consolidated
financial statements, on January 30, 2007, we entered into a Fourth Amended and Restated Credit Agreement (the "Agreement") for a new revolving credit facility with Union Bank of California
("UBOC"), as administrative agent and issuing lender, and the other lenders party thereto. Pursuant to the Agreement, UBOC acts as the administrative agent for a senior, first lien secured borrowing
base revolving credit facility (the "credit facility") in favor of us and certain of our wholly owned subsidiaries (which subsidiaries include Edge Petroleum Operating Company, Inc., Edge
Petroleum Exploration Company, Miller Oil Corporation and Miller Exploration Company) in an amount equal to $750 million, of which only $320 million was available under the borrowing
base established at the closing. The credit facility has a letter of credit sub-limit of $20 million. The credit facility is secured by substantially all of our oil and natural gas
properties. In connection with the credit facility, we paid the lenders fees in an amount equal to 1.00% of the initial borrowing base established under the credit facility, or $3.2 million, on
January 31, 2007. We paid approximately $0.6 million to the lenders for certain other administrative fees, fronting fees and work fees in connection with the credit facility. Upon
initiation of the credit facility, we terminated our existing Third Amended and Restated Credit Agreement described above and repaid the $129.0 million in borrowings under the Prior Credit
Facility with proceeds from the public offerings described below and in Note 11 to our consolidated financial statements.

The
credit facility matures on January 31, 2011 and bears interest at LIBOR plus an applicable margin ranging from 1.25% to 2.5% or Prime plus a margin of up to 0.25%, with an
unused commitment fee ranging from 0.50% to 0.25%. As of December 31, 2007, our interest rates on our outstanding Prime and LIBOR borrowings were 7.250% and 6.900%, respectively. As of
December 31, 2007, $260.0 million in borrowings were outstanding under the credit facility.

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



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The
credit facility includes other covenants and events of default that we believe are customary for similar facilities. It is an event of default under the credit facility if we undergo
a change in control. "Change in control," as defined in the credit facility, means any of the following events: (a) any "person" or "group" (within the meaning of Section 13(d) or 14(d)
of the Exchange Act) has become, directly or indirectly, the "beneficial owner" (as defined in Rules 13d-3 and 13d-5 under the Exchange Act, except that a person shall
be deemed to have "beneficial
ownership" of all such shares that any such person has the right to acquire, whether such right is exercisable immediately or only after the passage of time, by way of merger, consolidation or
otherwise), of a majority or more of our common stock on a fully-diluted basis, after giving effect to the conversion and exercise of all of our outstanding warrants, options and other securities
(whether or not such securities are then currently convertible or exercisable), (b) during any period of two consecutive calendar quarters, individuals who at the beginning of such period were
members of our Board of Directors cease for any reason to constitute a majority of the directors then in office unless (i) such new directors were elected by a majority of our directors who
constituted the Board of Directors at the beginning of such period (or by directors so elected) or (ii) the reason for such directors failing to constitute a majority is a result of retirement
by directors due to age, death or disability, or (c) we cease to own directly or indirectly all of the equity interests of each of our subsidiaries.

Our
available borrowing capacity under the credit facility was $40 million at December 31, 2007. The borrowing base was reduced from $320 million to
$300 million during the fourth quarter of 2007. We expect another reduction in the borrowing base, which will be redetermined in the second quarter of 2008, as a result of the sale of certain
non-core assets during the first quarter of 2008 and the reduction of total proved reserves as reported in the year-end reserve reports of our independent reserve engineers. As of
March 11, 2008, $250.0 million in borrowings were outstanding under our credit facility.

Shelf Registration Statement & Offerings

During the second quarter 2007, we filed a registration statement with the SEC which, as amended in a third quarter filing, registered securities of up to
$500 million of any combination of debt securities, preferred stock, common stock, warrants for debt securities or equity securities of the Company and guarantees of debt securities by our
subsidiaries. Net proceeds, terms and pricing of the offering of securities issued under the shelf registration statement will be determined at the time of the offerings. The shelf registration
statement does not provide assurance that we will or could sell any such securities. Our ability to utilize our shelf registration statement for the purpose of issuing, from time to time, any
combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities will depend upon, among other things, market conditions and the existence of
investors who wish to purchase our securities at prices acceptable to us. The shelf registration statement replaced a previous shelf registration statement, which registered offerings of up to
$390 million of securities.

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In
January 2007, we completed concurrent offerings of 10.925 million shares of our common stock and 2.875 million shares of our 5.75% Series A cumulative
convertible perpetual preferred stock ("Convertible Preferred Stock"). The shares were offered to the public at a price of $13.25 per share of
common stock and $50.00 per share of Convertible Preferred Stock. We received net proceeds of approximately $276.5 million from the offerings ($138.1 million from the common offering and
$138.4 million from the preferred offering), after deducting underwriting discounts and commissions and the expenses of the offerings. These proceeds were used to partially finance the
January 2007 Acquisition and to refinance our Prior Credit Facility.



As noted above, we completed the public offering of 2,875,000 shares of our Convertible Preferred Stock in January 2007. We used the $138.4 million
in net proceeds from this offering, along with the proceeds from the concurrent common stock offering and borrowings under our credit facility, to finance the January 2007 Acquisition and to
refinance our Prior Credit Facility.

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

No
dividends or other distributions (other than a dividend payable solely in shares of a like or junior ranking) may be paid or set apart for payment upon any shares ranking equally with
the Convertible Preferred Stock ("parity shares") or shares ranking junior to the Convertible Preferred Stock ("junior shares"), nor may any parity shares or junior shares be redeemed or acquired for
any consideration by 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 therefor have been set apart
on the Convertible Preferred Stock and any parity shares.

Liquidation preference.In the event of our voluntary or involuntary liquidation, winding-up or dissolution, each
holder of Convertible Preferred Stock will be entitled to receive and to be paid out of 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 indebtedness or senior stock, a liquidation preference in the amount of $50.00 per share of the Convertible Preferred
Stock, plus accumulated and unpaid dividends on the shares to the date fixed for liquidation, winding-up or dissolution.

Ranking.Our Convertible Preferred Stock ranks:



Mandatory conversion.On or after January 20, 2010, we may, at our option, cause shares of our Convertible Preferred
Stock to be automatically converted at the applicable conversion rate, but only if the closing sale price of our common stock for 20 trading days within a period of 30 consecutive

65

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trading
days ending on the trading day immediately preceding the date we give the conversion notice equals or exceeds 130% of the conversion price in effect on each such trading day.

Optional redemption.If fewer than 15% of the shares of Convertible Preferred Stock issued in the Convertible Preferred Stock
offering (including any additional shares issued pursuant to the underwriters' over-allotment option) are outstanding, 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 price equal to the liquidation preference of $50.00 plus any accrued and unpaid dividends, if any, on a share of
Convertible Preferred Stock to, but excluding, the redemption date, for each share of Convertible Preferred Stock.

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

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

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

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

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



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

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

In
addition, we may generally not, without the approval of the holders of at least 662/3% of the shares of our Convertible Preferred Stock then outstanding:



Off Balance Sheet Arrangements

The Company currently does not have any off balance sheet arrangements.

Contractual Cash Obligations

The following table summarizes our contractual cash obligations as of December 31, 2007 by payment due date:

|                                               |  | Total |         | Less than
1 Year |   | 1-3
Years |  | 4-5
Years |         | After
5 Years
|---------------------------------------------- |  | ----- | ------- | ---------------- | - | --------- |  | --------- | ------- | -------------
|
|Long-term debt(1)                              |  | $     | 260,000 |                  | $ |          |  | $         | 260,000 |              
|FIN 48 expected liabilities(2)                 |  |       | 534     |                  |   |          |  |           | 534     |              
|Operating leases                               |  |       | 6,513   |                  |   | 1,167     |  |           | 3,514   |              
|                                               |  |       |         |                  |   |           |  |           |         |              
|Total contractual cash obligations(3)(4)(5)(6) |  | $     | 267,047 |                  | $ | 1,167     |  | $         | 264,048 |              
|                                               |  |       |         |                  |   |           |  |           |         |              

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RISK MANAGEMENT ACTIVITIESDERIVATIVES AND HEDGING

Due to the volatility of oil and natural gas prices, we may enter into, from time to time, price-risk management transactions (e.g., swaps,
collars and floors) related to our expected oil and natural gas production to seek to achieve a more predictable cash flow, as well as to reduce exposure to commodity price fluctuations. While the use
of these arrangements may limit our ability to benefit from increases in the price of oil and natural gas, it is also intended to reduce our potential exposure to adverse price movements. See
"Approach to the Business" for a discussion of our current level of derivative contracts as it relates to expected production. Our arrangements, to the extent we enter into any, are intended to apply
to only a portion of our expected production, and thereby provide only partial price protection against declines in oil and natural gas prices while limiting our potential gains from future increases
in prices. None of these instruments are, at the time of their execution, intended to be used for trading purposes but may be deemed as such because of the expected decrease in our anticipated 2008
production. The use of derivative instruments involves the risk that the counterparties to such instruments will be unable to meet the financial obligations of such contracts. On a quarterly basis,
our management sets all of our price-risk management policies, including volumes, types of instruments and counterparties. These policies are implemented by management through the
execution of trades by the Chief Financial Officer after consultation and concurrence by the President and Chairman of the Board. Our Board of Directors monitors the Company's price-risk
management policies and trades on a monthly basis.

All
of these price-risk management transactions are considered derivative instruments and accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities(as
amended). These derivative instruments are intended to hedge our price risk and may be
considered hedges for economic purposes. There are two types of accounting treatments for derivatives, (i) mark-to-market accounting and (ii) cash flow hedge
accounting. For discussion of these accounting treatments, see Note 9 to our consolidated financial statements. We currently apply mark-to-market accounting treatment to
all of our derivative contracts. All derivatives are recorded on the balance sheet at fair value and the changes in fair value are presented in total revenue on the income

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statement.
The following table provides additional information regarding our various derivative transactions that were recorded at fair value on the balance sheet as of December 31, 2007.

Fair value of contracts outstanding at December 31, 2006

$
5,187Contracts realized or otherwise settled during the period


3,578Fair value of new contracts when entered into during 2007:Asset


619Liability


(3,093
)Changes in fair values attributable to changes in valuation techniques and assumptions


Other changes in fair values


(18,620
)Fair values of contracts outstanding at December 31, 2007

$
(12,329
)


The
following table details the fair value of our commodity-based derivative contracts by year of maturity and valuation methodology as of December 31, 2007.

|                                                    |           | Fair Value of Contracts at December 31, 2007 |  
|--------------------------------------------------- | --------- | -------------------------------------------- | -
|
|Prices actively quoted:                             |           | $                                            | 
|Prices provided by other external sources:          |           |                                              |  
|                                                    | Asset     |                                              |  
|                                                    | Liability |                                              |  
|Prices based on models and other valuation methods: |           |                                              | 
|                                                    |           |                                              |  
|                                                    |           | Total                                        |  
|                                                    |           |                                              |  

TAX MATTERS

At December 31, 2007, we had cumulative net operating loss carryforwards ("NOLs") for federal income tax purposes of approximately $146.5 million
that expire beginning in 2012. We also had state NOL carryforwards at December 31, 2007 of $19.2 million, which will expire in varying amounts between 2008 and 2027. These estimated NOLs
assume that certain items, primarily intangible drilling costs, have been written off for tax purposes in the current year. However, we have not made a final determination if an election will be made
to capitalize all or part of these items for tax purposes in the future. Our ability to utilize federal NOL carryforwards in cases where the NOL was acquired in a reorganization may be subject to
limitations under Section 382 of the Internal Revenue Code of 1986, as amended ("Section 382") if we undergo a majority ownership change as defined by Section 382.

We
would undergo a majority ownership change if, among other things, the stockholders who own or have owned, directly or indirectly, five percent or more of our common stock or are
otherwise treated as five percent stockholders under Section 382 and the regulations promulgated thereunder, increase their aggregate percentage ownership of our stock by more than
50 percentage points over the lowest percentage of stock owned by these stockholders at any time during the testing period, which is generally the three-year period preceding the
potential ownership change. In the event of a majority ownership change, Section 382 imposes an annual limitation on the amount of taxable income a corporation may offset with the NOL
carryforwards. Any unused annual limitation may be carried over to later years until the applicable expiration of the respective NOL carryforwards. The amount of the limitation may, under certain
circumstances, be increased by built-in gains held by us at the time of the change that are recognized in the five year period after the change. If we were to undergo a majority

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ownership
change, we would be required to record a reserve for some or all of the asset currently recorded on our balance sheet. As of December 31, 2007, we believe that there may have been an
additional change of ownership pursuant to Section 382 as a result of the concurrent public offerings of our common and preferred stock that occurred in January 2007. We cannot make
assurances that we will not undergo a majority ownership change in the future because an ownership change for federal tax purposes can occur based on trades among our existing stockholders. Whether we
undergo a majority ownership change may be a matter beyond our control. Further, in light of the ongoing strategic assessment process, we cannot provide any assurance that a potential sale or merger
will not reduce the availability of our NOL carryforward and other federal income tax attributes, which may be significantly limited or possibly eliminated.

At
December 31, 2007, under Section 382 rules, approximately $77 million of our total federal NOL carryforward of $146.5 million was subject to a potential
annual limitation of $12 million. Of that $77 million, $22 million was subject to further annual limitations. The $22 million amount represents the following two separate
limitations which occurred prior to 2007: (1) $17.4 million acquired in a December 2003 merger, which is subject to an annual limitation of approximately $1 million per
year and (2) $5.4 million acquired in a November 2005 acquisition, which is subject to an annual limitation of approximately $2 million per year.

In
June 2006, the FASB issued FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in accordance with SFAS No. 109, Accounting for Income Taxes. As a result of
the adoption of FIN 48 on January 1, 2007, we recognized a liability of $534,035 which reduced
the January 1, 2007 retained earnings balance. The amount recorded does not include interest as the anticipated adjustments more likely than not will result in no current tax due as a result of
NOL carryovers. All of the amounts of unrecognized tax benefits reported affect the effective tax rate through deferred tax accounting.

FIN 48
prescribes a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a
measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon ultimate settlement. If it is not more likely
than not that the benefit will be sustained on its technical merits, no benefit will be recorded. FIN 48 also
requires that the amount of interest expense to be recognized related to uncertain tax positions be computed by applying the applicable statutory rate of interest to the difference between the tax
position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken in a tax return. We also adopted FSP FIN 48-1 as of January 1,
2007, which provides that a company's tax position will be considered settled if the taxing authority has completed its examination, the company does not plan to appeal, and it is remote that the
taxing authority would reexamine the tax position in the future. We had no reserves prior to adoption at January 1, 2007. We recognize interest and penalties related to unrecognized tax
benefits in tax expense. However, we accrued no interest or penalties at December 31, 2007.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In December 2007, the FASB issued SFAS No. 141(R),Business Combinations("SFAS No. 141(R)").
SFAS No. 141(R) expands the definition of transactions and events that qualify as business combinations; requires that the acquired assets and liabilities, including contingencies, be recorded
at the fair value determined on the acquisition date and changes thereafter reflected in revenue, not goodwill; changes the recognition timing for restructuring costs; and requires acquisition costs
to be expensed as incurred. Adoption of SFAS No. 141(R) is required for combinations after December 15, 2008. Early adoption and retroactive application of SFAS No. 141(R) to
fiscal years preceding the effective date are not permitted. However, accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for
prior business combinations will impact tax expense instead of impacting the prior business combination

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accounting
starting January 1, 2009. We are currently evaluating the changes provided in SFAS No. 141(R) and believe it could have a material impact on our consolidated financial
statements if we undertake a significant acquisition or business combination.

In
December 2007, the FASB issued SFAS No. 160,Noncontrolling Interest in Consolidated Financial Statements("SFAS
No. 160"). SFAS No. 160 re-characterizes minority interests in consolidated subsidiaries as non-controlling interests and requires the classification of minority
interests as a component of equity. Under SFAS No. 160, a change in control will be measured at fair value, with any gain or loss recognized in earnings. The effective date for SFAS
No. 160 is for annual periods beginning on or after December 15, 2008. Early adoption and retroactive application of SFAS No. 160 to fiscal years preceding the effective date are
not permitted. We currently do not expect adoption of this statement to have an impact on our consolidated financial statements.

In
February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial LiabilitiesIncluding an
Amendment of FAS Statement No. 115. SFAS No. 159 gives companies the option of applying at specified election dates fair value accounting to certain financial
instruments and other items that are not currently required to be measured at fair value. If a company chooses to record eligible items at fair value, the company must report unrealized gains and
losses on those items in earnings at each subsequent reporting date. SFAS No. 159 also prescribes
presentation and disclosure requirements for assets and liabilities that are measured at fair value pursuant to this standard and pursuant to the guidance in SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities (as amended). SFAS No. 159 will be effective for fiscal year 2008. As the provisions
of SFAS No. 159 are applied prospectively, the impact to the Registrants will depend on the instruments selected for fair value measurement at the time of implementation. We are currently
assessing the impact that SFAS No. 159 will have on our consolidated financial statements.

In
September 2006, the FASB issued SFAS No. 157,Fair Value Measurements,which provides guidance for using fair value to
measure assets and liabilities. The standard also gives expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair
value, and the effect of fair value measurements on earnings. SFAS No. 157 does not expand the use of fair value in any new circumstances. SFAS No. 157 establishes a fair value hierarchy
that prioritizes the information used to develop fair value assumptions. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. In
February 2008, the FASB issued a FASB Staff Position ("FSP") on SFAS No. 157 that permits a one-year delay of the effective date for all non-financial assets and
non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We adopted SFAS No. 157
effective January 1, 2008, with the exceptions allowed under the FSP described above and do not expect any significant impact on our consolidated financial statements, other than
expanded disclosures beginning with our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2008.

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ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk from changes in interest rates and commodity prices. We use a credit facility, which has a floating interest rate, to finance a
portion of our operations. We are not subject to fair value risk resulting from changes in our floating interest rates. The use of floating rate debt instruments provides a benefit due to downward
interest rate movements but does not limit us to exposure from future increases in interest rates. Based on the year-end December 31, 2007 outstanding borrowings and interest rates
of 7.250% and 6.900% applied to various borrowings, a 10% change in these interest rates would result in an increase or decrease in interest expense of approximately $1.7 million on an annual
basis.

In
the normal course of business, we enter into derivative transactions, including commodity price collars, swaps and floors to mitigate our exposure to commodity price movements, but
not for trading or speculative purposes. While the use of these arrangements may limit the benefit to us of increases in the price of oil and natural gas, it also limits the downside risk of adverse
price movements. During early 2007, we put in place several natural gas and crude oil collars to hedge our expected 2008 and 2009 production to achieve a more predictable cash flow. As a result of
recent changes to our forecasted 2008 production and the impact of certain asset divestitures, both of which have reduced expected production as compared to that expected at the time we entered into
the derivative contracts, we currently have approximately 110% and 150% of our anticipated 2008 natural gas and crude oil production, respectively, covered by derivative contracts. This overhedged
position exposes us to greater risk of commodity price increases because we will not have the physical production cash inflows to offset any potential losses incurred on the portion of the contracts
that are overhedged. Please refer to Note 9 to our consolidated financial statements for a discussion of these contracts. The following is a list of contracts outstanding at December 31,
2007:

|Transaction Date |  | Transaction Type |  | Beginning |  | Ending   |  | Price Per Unit  |  | Volumes Per Day |  | Fair Value Outstanding as of December 31, 2007 |        
|---------------- |  | ---------------- |  | --------- |  | -------- |  | --------------- |  | --------------- |  | ---------------------------------------------- | -------
|
|Natural Gas (1): |  |                  |  |           |  |          |  |                 |  |                 |  |                                                |        
|01/07            |  | Collar           |  | 01/01/08  |  | 12/31/08 |  | $7.50 - $9.00   |  | 20,000 MMBtu    |  |                                                | 1,096  
|01/07            |  | Collar           |  | 01/01/08  |  | 12/31/08 |  | $7.50 - $9.00   |  | 10,000 MMBtu    |  |                                                | 619    
|01/07            |  | Collar           |  | 01/01/08  |  | 12/31/08 |  | $7.50 - $9.02   |  | 10,000 MMBtu    |  |                                                | 599    
|04/07            |  | Collar           |  | 01/01/09  |  | 12/31/09 |  | $7.75 - $10.00  |  | 10,000 MMBtu    |  |                                                | 125    
|10/07            |  | Collar           |  | 01/01/09  |  | 12/31/09 |  | $7.75 - $10.08  |  | 10,000 MMBtu    |  |                                                | 187    
|Crude Oil (2):   |  |                  |  |           |  |          |  |                 |  |                 |  |                                                |        
|12/06            |  | Swap             |  | 01/01/08  |  | 12/31/08 |  | $66.00          |  | 1,500 Bbl       |  |                                                | (14,541
|10/07            |  | Collar           |  | 01/01/09  |  | 12/31/09 |  | $70.00 - $93.55 |  | 300 Bbl         |  |                                                | (414   
|                 |  |                  |  |           |  |          |  |                 |  |                 |  |                                                |        
|                 |  |                  |  |           |  |          |  |                 |  |                 |  | $                                              | (12,329
|                 |  |                  |  |           |  |          |  |                 |  |                 |  |                                                |        

---

At
December 31, 2007, the fair value of the outstanding contracts was a net liability of approximately $12.3 million (SeeITEM 7. "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSRISK MANAGEMENT

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ACTIVITIESDERIVATIVES
AND HEDGING"). A 10% change in the commodity price per unit, as long as the price is either above the ceiling or
below the floor price of each contract, would cause the fair value total of the hedge to increase or decrease by approximately $1.7 million.

All
of our business is conducted in the United States with transactions denominated in U.S. dollars and, as a result, we do not have material exposure to currency exchange-rate risks

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

None.

ITEM 9A.    CONTROLS AND PROCEDURES

(a)Disclosure Controls and Procedures.We maintain disclosure
controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange
Commission ("SEC") under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and
forms, and that information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding
required disclosure.

In
accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. As
described below under Management's Annual Report on Internal Control over Financial Reporting, our CEO and CFO have concluded that, as of the end of the period covered by this Annual Report on
Form 10-K, the Company's disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports filed or
submitted under
the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms.

BDO
Seidman, LLP's audit report, dated March 12, 2008, expressed an unqualified opinion on our consolidated financial statements and its assessment of our internal controls
over financial reporting is included herein under paragraph (d).

(b)Management's Annual Report on Internal Control over Financial
Reporting.Management, including the CEO and CFO, has the responsibility for establishing and maintaining adequate internal control over financial reporting, as
defined in the Exchange Act, Rule 13a-15(f). Internal control over financial reporting is a process designed by, or under the supervision of, the Company's principal executive and
principal financial officers, or persons performing similar functions and influenced by the Company's Board of Directors, management and other personnel, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America
("GAAP"). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become inadequate or insufficient because of changes

73

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in
operating conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A
control deficiency exists when the design or operation of a control does not allow management or employees, in the ordinary course of performing their assigned functions, to prevent or
detect misstatements on a timely basis. A significant deficiency is a control deficiency, or combination of control deficiencies, that adversely affects the Company's ability to initiate, authorize,
record, process, or report external financial data reliably in accordance with GAAP, such that there is a more than remote likelihood that a misstatement of the Company's annual or interim financial
statements that is more than inconsequential will not be prevented or detected. A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote
likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

Management
assessed internal control over financial reporting of the Company and subsidiaries as of December 31, 2007. The Company's management conducted its assessment in
accordance with theInternal ControlIntegrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission
("COSO"). Management has concluded that the internal control over financial reporting was effective as of December 31, 2007.

BDO
Seidman, LLP, the independent registered public accounting firm who also audited the Company's consolidated financial statements, has issued its own attestation report on the
effectiveness of internal controls over our financial reporting as of December 31, 2007, which is filed herewith.

(c)Changes in Internal Control Over Financial Reporting.There
have not been any changes in the Company's internal control over financial reporting during the fiscal quarter ended December 31, 2007 that have materially affected, or are reasonably likely to
materially affect, the Company's internal control over financial reporting.

74

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(d)Report of Independent Registered Public Accounting Firm

Board
of Directors and Stockholders
Edge Petroleum Corporation
Houston, Texas

We
have audited Edge Petroleum Corporation's internal control over financial reporting as of December 31, 2007, based on criteria established inInternal
ControlIntegrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Company's management is
responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying
"Item 9A, Management's Report on Internal Control Over Financial Reporting". Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our
audit.

We
conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control
over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our
audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A
company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

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

In
our opinion, Edge Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO
criteria.

We
also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Edge Petroleum Corporation as
of December 31, 2007 and 2006 and the related consolidated statements of operations, comprehensive income (loss), stockholders' equity, and cash flows for each of the three years in the period
ended December 31, 2007, and our report dated March 12, 2008 expressed an unqualified opinion thereon.

|/S/ BDO SEIDMAN, LLP                        |  | 
|------------------------------------------- |  | 
|BDO SEIDMAN, LLP
HOUSTON, TX
MARCH 12, 2008 |  | 

ITEM 9B.    OTHER INFORMATION

None.

75

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PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information regarding directors and executive officers required underITEM 10will be contained within the
definitive Proxy Statement for the Company's 2008 Annual Meeting of Shareholders (the "Proxy Statement") under the headings "Election of Directors," "Meetings and Committees 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 the Securities and Exchange
Commission not later than 120 days after December 31, 2007, or the Company will file an amendment to this Form 10-K within the same time period that includes the
required information. Pursuant to Item 401(b) of Regulation S-K certain of the information required by this item with respect to our executive officers is set forth in
Part I of this report.

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

ITEM 11.    EXECUTIVE COMPENSATION

The information required byITEM 11will be contained in the Proxy Statement under the headings "Executive
Compensation," "Compensation Committee Interlocks and Insider Participation," "Compensation Committee Report" and "2007 Director Compensation" and is incorporated herein by reference.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required byITEM 12will be contained in the Proxy Statement under the headings "Security
Ownership of Certain Beneficial Owners and Management" and "Equity Compensation Plan Information" and is incorporated herein by reference.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required byITEM 13will be contained in the Proxy Statement under the heading "Transactions with
Related Persons" and is incorporated herein by reference.

ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required byITEM 14will be contained in the Proxy Statement under the heading "Approval of
Appointment of Independent Public Accountants" and is incorporated herein by reference.

76

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PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES



|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).                                                                                                                                                                                                                                                                                                                               

77

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|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 (File No. 000-22149)).                                                                                                                                                                                                                                                                                                                                                                                  
|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 (File No. 000-22149)
).                                                                                                                                                                                                                                                                                                                                        
|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).                                                                                                                                                                                                                                                                                                                                                                        
|3.7 |  |  |  | Certificate of Designations establishing the 5.75% Series A cumulative convertible perpetual preferred stock, dated January 25, 2007 (Incorporated by reference to exhibit 3.1 to Edge's Current Report on Form 8-K filed
January 30, 2007).                                                                                                                                                                                                                                                                                                                               
|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)).                                                                                                                                                                                                                                                                                                     

78

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|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)).                                                                                                                                                     
|10.3  |  |  |  | Employment Agreement dated as of November 16, 1998, by and between the Company and John W. Elias (Incorporated by reference from exhibit 10.12 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998 (File
No. 000-22149)).                                                                                                    
|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 (File No. 000-22149)).                   
|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 (File No. 000-22149)).                  
|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 (File No. 000-22149)).                                                                         
|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 (File No. 000-22149)).                                                                              
|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)
).                                                                                                                            

79

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|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 29, 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 16, 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 5, 2007). 
|*12.1   |  |  |  | Statement of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.                                                                                                                                                                          
|*21.1   |  |  |  | Subsidiaries of the Company.                                                                                                                                                                                                                                                    
|*23.1   |  |  |  | Consent of BDO Seidman, LLP.                                                                                                                                                                                                                                                    
|*23.2   |  |  |  | Consent of Ryder Scott Company.                                                                                                                                                                                                                                                 
|*23.3   |  |  |  | Consent of W. D. Von Gonten & Co.                                                                                                                                                                                                                                               
|*31.1   |  |  |  | Certification by John W. Elias, Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                             

80

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|*31.2 |  |  |  | Certification by Michael G. Long, Chief Financial and Accounting Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|----- |  | - |  | ------------------------------------------------------------------------------------------------------------------------------------
|*32.1 |  |  |  | Certification by John W. Elias, Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                 
|*32.2 |  |  |  | Certification by Michael G. Long, Chief Financial and Accounting Officer, 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, 2007.                                       
|*99.2 |  |  |  | Summary of Reserve Report of W. D. Von Gonten & Co. Petroleum Engineers as of December 31, 2007.                                    

---

81

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SIGNATURES

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

| |  | Edge Petroleum Corporation
| |  | --------------------------
| |  | By                        

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in
the capacities and on the dates indicated.

|By |  | /s/JOHN W. ELIASJohn W. Elias
Chief Executive Officer and Chairman of the Board
(Principal Executive Officer)                                 |  | Date: March 13, 2008
|-- |  | --------------------------------------------------------------------------------------------------------------------------------------------- |  | --------------------
|By |  | /s/MICHAEL G. LONGMichael G. Long
Executive Vice President and
Chief Financial Officer
(Principal Financial and Principal Accounting Officer) |  | Date: March 13, 2008
|By |  | /s/THURMON M. ANDRESSThurmon Andress
Director                                                                                                 |  | Date: March 13, 2008
|By |  | /s/VINCENT S. ANDREWSVincent Andrews
Director                                                                                                 |  | Date: March 13, 2008
|By |  | /s/JONATHAN CLARKSONJonathan Clarkson
Director                                                                                                |  | Date: March 13, 2008
|By |  | /s/MICHAEL A. CREELMichael A. Creel
Director                                                                                                  |  | Date: March 13, 2008
|By |  | /s/JOHN SFONDRINIJohn Sfondrini
Director                                                                                                      |  | Date: March 13, 2008
|By |  | /s/ROBERT W. SHOWERRobert W. Shower
Director                                                                                                  |  | Date: March 13, 2008
|By |  | /s/DAVID F. WORKDavid F. Work
Director                                                                                                        |  | Date: March 13, 2008

82

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EDGE PETROLEUM CORPORATION

Index to Consolidated Financial Statements and Supplementary Information



|CONSOLIDATED FINANCIAL STATEMENTS                                                                           |                                                                |    
|----------------------------------------------------------------------------------------------------------- | -------------------------------------------------------------- | ---
|Audited Financial Statements:                                                                               |                                                                |    
|Report of Independent Registered Public Accounting Firm                                                     |                                                                | F-2
|Consolidated Balance Sheets as of December 31, 2007 and 2006                                                |                                                                | F-3
|Consolidated Statements of Operations for the Years Ended
December 31, 2007, 2006 and 2005                  |                                                                | F-4
|Consolidated Statements of Comprehensive Income (Loss) for the Years Ended
December 31, 2007, 2006 and 2005 |                                                                | F-5
|Consolidated Statements of Cash Flows for the Years Ended
December 31, 2007, 2006 and 2005                  |                                                                | F-6
|Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 2007, 2006 and 2005        |                                                                | F-7
|Notes to Consolidated Financial Statements                                                                  |                                                                | F-8
|Unaudited Information:                                                                                      |                                                                |    
|                                                                                                            | Supplementary Information to Consolidated Financial Statements |    

CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

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

F-1

---





Report of Independent Registered Public Accounting Firm

Board
of Directors and Stockholders
Edge Petroleum Corporation
Houston, Texas

We
have audited the accompanying consolidated balance sheets of Edge Petroleum Corporation as of December 31, 2007 and 2006 and the related consolidated statements of operations,
comprehensive income (loss), stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We
conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether 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 by management, as well as evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

As
discussed in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company adopted the provisions of Statement of Financial Accounting
Standards No. 123(R), "Share-Based Payment" and effective January 1, 2007 the Company adopted the provision of Financial Accounting Standards Board Interpretation No. 48,
"Accounting for Uncertainty in Income Taxes".

In
our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Edge Petroleum Corporation at
December 31, 2007 and 2006, and the
results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States
of America.

We
also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) Edge Petroleum Corporation's internal control over financial
reporting as of December 31, 2007, based on criteria established inInternal ControlIntegrated Frameworkissued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 12, 2008 expressed an unqualified opinion thereon.

|/S/ BDO SEIDMAN, LLP          |  | 
|----------------------------- |  | 
|BDO Seidman, LLP              |  | 
|Houston, Texas
March 12, 2008 |  | 

F-2

---





EDGE PETROLEUM CORPORATION        CONSOLIDATED BALANCE SHEETS

|                                                                                                                                                                                                           |                                                                                                                                                                  | December 31,              
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------- | --------------------------
|
|
|ASSETS                                                                                                                                                                                                     |                                                                                                                                                                  |                           
|CURRENT ASSETS:                                                                                                                                                                                            |                                                                                                                                                                  |                           
|                                                                                                                                                                                                           | Cash and cash equivalents                                                                                                                                        |                           
|                                                                                                                                                                                                           | Accounts receivable, trade, net of allowance                                                                                                                     |                           
|                                                                                                                                                                                                           | Accounts receivable, joint interest owners and other, net of allowance                                                                                           |                           
|                                                                                                                                                                                                           | Deferred tax asset                                                                                                                                               |                           
|                                                                                                                                                                                                           | Derivative financial instruments                                                                                                                                 |                           
|                                                                                                                                                                                                           | Other current assets                                                                                                                                             |                           
|                                                                                                                                                                                                           |                                                                                                                                                                  |                           
|                                                                                                                                                                                                           |                                                                                                                                                                  | Total current assets      
|PROPERTY AND EQUIPMENT, Netfull cost method of accounting for oil and natural gas properties (including unevaluated costs of $34.9 million and $57.6 million at December 31, 2007 and 2006, respectively) |                                                                                                                                                                  |                           
|OTHER ASSETS                                                                                                                                                                                               |                                                                                                                                                                  |                           
|                                                                                                                                                                                                           |                                                                                                                                                                  |                           
|TOTAL ASSETS                                                                                                                                                                                               |                                                                                                                                                                  | $                         
|                                                                                                                                                                                                           |                                                                                                                                                                  |                           
|LIABILITIES AND STOCKHOLDERS' EQUITY                                                                                                                                                                       |                                                                                                                                                                  |                           
|CURRENT LIABILITIES:                                                                                                                                                                                       |                                                                                                                                                                  |                           
|                                                                                                                                                                                                           | Accounts payable, trade                                                                                                                                          |                           
|                                                                                                                                                                                                           | Accrued liabilities                                                                                                                                              |                           
|                                                                                                                                                                                                           | Derivative financial instruments                                                                                                                                 |                           
|                                                                                                                                                                                                           | Accrued interest payable                                                                                                                                         |                           
|                                                                                                                                                                                                           | Deferred tax liability                                                                                                                                           |                           
|                                                                                                                                                                                                           | Asset retirement obligation                                                                                                                                      |                           
|                                                                                                                                                                                                           |                                                                                                                                                                  |                           
|                                                                                                                                                                                                           |                                                                                                                                                                  | Total current liabilities 
|ASSET RETIREMENT OBLIGATIONlong-term                                                                                                                                                                      |                                                                                                                                                                  |                           
|DERIVATIVE FINANCIAL INSTRUMENTSlong-term                                                                                                                                                                 |                                                                                                                                                                  |                           
|DEFERRED TAX LIABILITYlong-term                                                                                                                                                                           |                                                                                                                                                                  |                           
|OTHER NON-CURRENT LIABILITIES                                                                                                                                                                              |                                                                                                                                                                  |                           
|LONG-TERM DEBT                                                                                                                                                                                             |                                                                                                                                                                  |                           
|                                                                                                                                                                                                           |                                                                                                                                                                  |                           
|                                                                                                                                                                                                           |                                                                                                                                                                  | Total liabilities         
|                                                                                                                                                                                                           |                                                                                                                                                                  |                           
|COMMITMENTS AND CONTINGENCIES (Note 14)                                                                                                                                                                    |                                                                                                                                                                  |                           
|STOCKHOLDERS' EQUITY                                                                                                                                                                                       |                                                                                                                                                                  |                           
|                                                                                                                                                                                                           | Preferred stock, $0.01 par value; 5,000,000 shares authorized; 2,875,000 issued and outstanding at December 31, 2007 and none at December 31, 2006               |                           
|                                                                                                                                                                                                           | Common stock, $0.01 par value; 60,000,000 shares authorized; 28,544,160 and 17,442,229 shares issued and outstanding at December 31, 2007 and 2006, respectively |                           
|                                                                                                                                                                                                           | Additional paid-in capital                                                                                                                                       |                           
|                                                                                                                                                                                                           | Retained earnings                                                                                                                                                |                           
|                                                                                                                                                                                                           |                                                                                                                                                                  |                           
|                                                                                                                                                                                                           |                                                                                                                                                                  | Total stockholders' equity
|                                                                                                                                                                                                           |                                                                                                                                                                  |                           
|TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                                                                                                                                                                 |                                                                                                                                                                  | $                         
|                                                                                                                                                                                                           |                                                                                                                                                                  |                           

See
accompanying notes to the consolidated financial statements.

F-3

---



EDGE PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

EDGE PETROLEUM CORPORATION        CONSOLIDATED STATEMENTS OF OPERATIONS

|                                                             |                                                                                  | Year Ended December 31,  |       
|------------------------------------------------------------ | -------------------------------------------------------------------------------- | ------------------------ | ------
|
|
|OIL AND NATURAL GAS REVENUE:                                 |                                                                                  |                          |       
|                                                             | Oil and natural gas sales                                                        |                          | $     
|                                                             | Gain (loss) on derivatives                                                       |                          |       
|                                                             |                                                                                  |                          |       
|                                                             |                                                                                  | Total revenue            |       
|                                                             |                                                                                  |                          |       
|OPERATING EXPENSES:                                          |                                                                                  |                          |       
|                                                             | Oil and natural gas operating expenses including production and ad valorem taxes |                          |       
|                                                             | Depletion, depreciation, amortization and accretion                              |                          |       
|                                                             | Impairment of oil and natural gas properties                                     |                          |       
|                                                             | General and administrative expenses                                              |                          |       
|                                                             |                                                                                  |                          |       
|                                                             |                                                                                  | Total operating expenses |       
|                                                             |                                                                                  |                          |       
|OPERATING INCOME (LOSS)                                      |                                                                                  |                          | 21,492
|OTHER INCOME (EXPENSE):                                      |                                                                                  |                          |       
|                                                             | Interest expense, net of amounts capitalized                                     |                          |       
|                                                             | Amortization of deferred loan costs                                              |                          |       
|                                                             | Interest income                                                                  |                          |       
|                                                             |                                                                                  |                          |       
|INCOME (LOSS) BEFORE INCOME TAXES                            |                                                                                  |                          | 10,305
|INCOME TAX (EXPENSE) BENEFIT                                 |                                                                                  |                          | (3,733
|                                                             |                                                                                  |                          |       
|NET INCOME (LOSS)                                            |                                                                                  |                          | 6,572 
|                                                             | Preferred Stock Dividends                                                        |                          |       
|                                                             |                                                                                  |                          |       
|NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS           |                                                                                  | $                        | (1,005
|                                                             |                                                                                  |                          |       
|BASIC EARNINGS (LOSS) PER SHARE                              |                                                                                  | $                        | (0.04 
|                                                             |                                                                                  |                          |       
|DILUTED EARNINGS (LOSS) PER SHARE                            |                                                                                  | $                        | (0.04 
|                                                             |                                                                                  |                          |       
|BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING   |                                                                                  |                          | 27,613
|                                                             |                                                                                  |                          |       
|DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING |                                                                                  |                          | 27,613
|                                                             |                                                                                  |                          |       

See
accompanying notes to the consolidated financial statements.

F-4

---





EDGE PETROLEUM CORPORATION        CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

|                                                   |                                                                           | Year Ended December 31,   |                                  
|-------------------------------------------------- | ------------------------------------------------------------------------- | ------------------------- | ---------------------------------
|
|
|NET INCOME (LOSS)                                  |                                                                           | $                         | 6,572                            
|                                                   |                                                                           | Preferred Stock Dividends |                                  
|                                                   |                                                                           |                           |                                  
|NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS |                                                                           |                           | (1,005                           
|OTHER COMPREHENSIVE INCOME (LOSS), net of tax:     |                                                                           |                           |                                  
|                                                   | Change in fair value of outstanding hedging and derivative instruments(1) |                           |                                  
|                                                   | Reclassification of hedging and derivative losses(2)                      |                           |                                  
|                                                   |                                                                           |                           |                                  
|                                                   |                                                                           |                           | Other comprehensive income (loss)
|                                                   |                                                                           |                           |                                  
|COMPREHENSIVE INCOME (LOSS)                        |                                                                           | $                         | (1,005                           
|                                                   |                                                                           |                           |                                  
|(1) net of income taxes                            |                                                                           | $                         |                                 
|(2) net of income taxes                            |                                                                           | $                         |                                 

See
accompanying notes to the consolidated financial statements.

F-5

---



EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Continued)

EDGE PETROLEUM CORPORATION        CONSOLIDATED STATEMENTS OF CASH FLOWS

|                                                     |                                                                                          | Year Ended December 31,                                           |                                          
|---------------------------------------------------- | ---------------------------------------------------------------------------------------- | ----------------------------------------------------------------- | -----------------------------------------
|
|
|CASH FLOWS FROM OPERATING ACTIVITIES:                |                                                                                          |                                                                   |                                          
|                                                     | Net income (loss)                                                                        |                                                                   | $                                        
|                                                     | Adjustments to reconcile net income (loss) to net cash provided by operating activities: |                                                                   |                                          
|                                                     |                                                                                          | Unrealized (gain) loss on the fair value of derivatives           |                                          
|                                                     |                                                                                          | Loss on property                                                  |                                          
|                                                     |                                                                                          | Depletion, depreciation, amortization and accretion               |                                          
|                                                     |                                                                                          | Impairment of oil and natural gas properties                      |                                          
|                                                     |                                                                                          | Amortization of deferred loan costs                               |                                          
|                                                     |                                                                                          | Deferred income taxes                                             |                                          
|                                                     |                                                                                          | Share-based compensation cost                                     |                                          
|                                                     |                                                                                          | Bad debt expense                                                  |                                          
|                                                     | Changes in operating assets and liabilities:                                             |                                                                   |                                          
|                                                     |                                                                                          | (Increase) decrease in accounts receivable, trade                 |                                          
|                                                     |                                                                                          | (Increase) decrease in accounts receivable, joint interest owners |                                          
|                                                     |                                                                                          | Increase in other assets                                          |                                          
|                                                     |                                                                                          | Increase (decrease) in accounts payable, trade                    |                                          
|                                                     |                                                                                          | Increase in accrued interest payable                              |                                          
|                                                     |                                                                                          | Increase (decrease) in accrued liabilities                        |                                          
|                                                     |                                                                                          |                                                                   |                                          
|                                                     |                                                                                          |                                                                   | Net cash provided by operating activities
|                                                     |                                                                                          |                                                                   |                                          
|CASH FLOWS FROM INVESTING ACTIVITIES:                |                                                                                          |                                                                   |                                          
|                                                     | Oil and natural gas property and equipment additions                                     |                                                                   |                                          
|                                                     | Drilling advances                                                                        |                                                                   |                                          
|                                                     | Proceeds from the sale of oil and natural gas properties                                 |                                                                   |                                          
|                                                     | Acquisition of assets in January 2007                                                    |                                                                   |                                          
|                                                     | Acquisition of Cinco Energy Corporation, net of cash acquired                            |                                                                   |                                          
|                                                     |                                                                                          |                                                                   |                                          
|                                                     |                                                                                          |                                                                   | Net cash used in investing activities    
|                                                     |                                                                                          |                                                                   |                                          
|CASH FLOWS FROM FINANCING ACTIVITIES:                |                                                                                          |                                                                   |                                          
|                                                     | Borrowings from long-term debt                                                           |                                                                   |                                          
|                                                     | Repayments on long-term debt                                                             |                                                                   |                                          
|                                                     | Preferred dividends paid                                                                 |                                                                   |                                          
|                                                     | Proceeds of preferred stock offering                                                     |                                                                   |                                          
|                                                     | Costs of preferred stock offering                                                        |                                                                   |                                          
|                                                     | Proceeds of common stock offering                                                        |                                                                   |                                          
|                                                     | Costs of common stock offering                                                           |                                                                   |                                          
|                                                     | Net proceeds from issuance of common stock                                               |                                                                   |                                          
|                                                     | Deferred loan costs                                                                      |                                                                   |                                          
|                                                     |                                                                                          |                                                                   |                                          
|                                                     |                                                                                          |                                                                   | Net cash provided by financing activities
|                                                     |                                                                                          |                                                                   |                                          
|NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS |                                                                                          |                                                                   | 5,082                                    
|CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR         |                                                                                          |                                                                   | 2,081                                    
|                                                     |                                                                                          |                                                                   |                                          
|CASH AND CASH EQUIVALENTS, END OF YEAR               |                                                                                          | $                                                                 | 7,163                                    
|                                                     |                                                                                          |                                                                   |                                          

See
accompanying notes to the consolidated financial statements.

F-6

---





EDGE PETROLEUM CORPORATION        CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

|                                                                    |  | Preferred Stock |  | Common Stock |    |  |        |  |   |     |  |   |        
|------------------------------------------------------------------- |  | --------------- |  | ------------ | -- |  | ------ |  | - | --- |  | - | -------
|
|
|
|BALANCE, DECEMBER 31, 2004                                          |  |                |  | $            |   |  | 16,536 |  | $ | 165 |  | $ | 126,957
|Issuance of common stock                                            |  |                |  |              |   |  | 681    |  |   | 7   |  |   | 7,776  
|Compensation costrestricted stock                                  |  |                |  |              |   |  |       |  |   |    |  |   | 974    
|Compensation costrepriced options                                  |  |                |  |              |   |  |       |  |   |    |  |   | 1,628  
|Tax benefit associated with exercise of non-qualified stock options |  |                |  |              |   |  |       |  |   |    |  |   | 507    
|Change in valuation of hedging instruments                          |  |                |  |              |   |  |       |  |   |    |  |   |       
|Net income                                                          |  |                |  |              |   |  |       |  |   |    |  |   |       
|                                                                    |  |                 |  |              |    |  |        |  |   |     |  |   |        
|BALANCE, DECEMBER 31, 2005                                          |  |                |  |              |   |  | 17,217 |  |   | 172 |  |   | 137,842
|Issuance of common stock                                            |  |                |  |              |   |  | 225    |  |   | 2   |  |   | 1,404  
|Compensation costrestricted stock                                  |  |                |  |              |   |  |       |  |   |    |  |   | 1,908  
|Compensation costrepriced options                                  |  |                |  |              |   |  |       |  |   |    |  |   | 69     
|Tax benefit associated with exercise of non-qualified stock options |  |                |  |              |   |  |       |  |   |    |  |   | 462    
|Change in valuation of hedging instruments                          |  |                |  |              |   |  |       |  |   |    |  |   |       
|Net loss                                                            |  |                |  |              |   |  |       |  |   |    |  |   |       
|                                                                    |  |                 |  |              |    |  |        |  |   |     |  |   |        
|BALANCE, DECEMBER 31, 2006                                          |  |                |  |              |   |  | 17,442 |  |   | 174 |  |   | 141,685
|Issuance of preferred stock                                         |  | 2,875           |  |              | 29 |  |       |  |   |    |  |   | 143,721
|Costs of preferred stock offering                                   |  |                |  |              |   |  |       |  |   |    |  |   | (5,315 
|Issuance of common stock                                            |  |                |  |              |   |  | 10,925 |  |   | 109 |  |   | 144,647
|Costs of common stock offering                                      |  |                |  |              |   |  |       |  |   |    |  |   | (6,665 
|Issuance of common stock                                            |  |                |  |              |   |  | 177    |  |   | 2   |  |   | 548    
|Stock based compensation costs                                      |  |                |  |              |   |  |       |  |   |    |  |   | 3,404  
|Tax benefit associated with exercise of non-qualified stock options |  |                |  |              |   |  |       |  |   |    |  |   | (217   
|Adoption of FIN 48                                                  |  |                |  |              |   |  |       |  |   |    |  |   |       
|Preferred stock dividends ($0.71875 per share)                      |  |                |  |              |   |  |       |  |   |    |  |   |       
|Net income                                                          |  |                |  |              |   |  |       |  |   |    |  |   |       
|                                                                    |  |                 |  |              |    |  |        |  |   |     |  |   |        
|BALANCE, DECEMBER 31, 2007                                          |  | 2,875           |  | $            | 29 |  | 28,544 |  | $ | 285 |  | $ | 421,808
|                                                                    |  |                 |  |              |    |  |        |  |   |     |  |   |        

See accompanying notes to the consolidated financial statements.

F-7

---





EDGE PETROLEUM CORPORATION        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.    ORGANIZATION AND NATURE OF OPERATIONS

GeneralEdge Petroleum Corporation(the "Company") was organized as a Delaware corporation in August 1996 in connection
with its initial public offering and the related combination of certain entities that held interests in Edge Joint Venture II (the "Joint Venture") and certain other oil and natural gas
properties; herein referred to as the "Combination". In a series of transactions the Company issued an aggregate of 4.7 million shares of common stock and received in exchange 100% of
the ownership interests in the Joint Venture and certain other oil and natural gas properties. In March 1997, and contemporaneously with the Combination, the Company completed the initial
public offering of 2.8 million shares of its common stock (the "Offering"). In December 2003, the Company completed a merger with Miller Exploration Company ("Miller") in a stock for
stock transaction, in which the Company issued 2.6 million shares of common stock to the shareholders of Miller. In December 2004 and January 2005, the Company completed a public
offering of common stock in which 4.0 million shares were issued in order to fund the asset acquisition 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 Production Company (see Note 6). In January 2007, the
Company completed two concurrent public offerings in which approximately 2.9 million shares of preferred stock and approximately 10.9 million shares of common stock were issued in order
to partially fund a January 2007 asset acquisition.

Nature of OperationsThe Company is an independent oil and natural gas company engaged in the exploration, development,
acquisition and production of crude oil and natural gas properties in the United States. The Company's resources and assets are managed and its results are reported as one operating segment. The
Company conducts its operations primarily along the onshore United States Gulf Coast, with an emphasis in Texas, Mississippi, New Mexico, and Louisiana. In its exploration efforts the Company
emphasizes an integrated geologic interpretation method incorporating 3-D seismic technology and advanced visualization and data analysis techniques utilizing
state-of-the-art computer hardware and software.

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of ConsolidationThe consolidated financial statements include the accounts of all majority owned subsidiaries of
the Company, including Edge Petroleum Operating Company Inc., Edge Petroleum Exploration Company, Edge Petroleum Production Company (formerly Cinco Energy Corporation), Miller Oil Corporation,
and Miller Exploration Company, which are 100% owned subsidiaries of the Company. All intercompany balances and transactions have been eliminated in consolidation.

Changes in Accounting PrinciplesBeginning January 1, 2007, the Company adopted the provisions of Financial Accounting
Standards Board ("FASB") Interpretation No. 48Accounting for Uncertainty in Income Taxes (an interpretation of FASB Statement No. 109)("FIN 48"). This interpretation clarified the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute
for a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on de-recognitions, classification, interest and penalties, accounting in interim
periods, disclosure and transition. The Company also adopted FASB Staff Position No. FIN 48-1,Definition of Settlement in FASB Interpretation
No. 48("FSP FIN 48-1") as of January 1, 2007. FSP FIN 48-1 provides that a company's tax position will be considered
settled if the taxing authority has completed its examination, the company does not plan to

F-8

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

appeal,
and it is remote that the taxing authority would reexamine the tax position in the future (see Note 16).

Cash and Cash EquivalentsThe Company considers all highly liquid investments with original maturities of three 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 and payables approximates fair value because of the short-term nature of these items. The carrying
amount of long-term debt as of December 31, 2007 and 2006 approximates fair value because the interest rates are variable and reflective of market rates. Derivative instruments are
reflected at fair value based on quotes obtained from our counterparties.

Revenue RecognitionThe Company recognizes oil and natural gas revenue from its interests in producing wells as oil and
natural gas is produced and sold from those wells. Oil and natural gas sold by the Company is not significantly different from the Company's share of production.

Delivery CommitmentsDuring 2007, the Company executed a gas gathering and compression services agreement with Frontier
Midstream, LLC ("Frontier"). Following execution of such agreement, Frontier expedited the installation of the Rose Bud system in White County, Arkansas, including the high and low pressure
gathering lines, dehydration, compression and the interconnect with Ozark, in order to accommodate the Company's desire to be able to deliver natural gas as soon as its wells were completed. At the
time of signing the contract, the Company had completed and tested two productive wells in the Moorefield shale in Arkansas. The Rose Bud system was installed, operational and ready to receive the
Company's production in June 2007. The contract minimum commitment to Frontier is 2.7 Bcf over a three year period for the pipeline interconnect. This line carries a $0.29 per Mcf
deficiency rate, for a total commitment for the pipeline of approximately $0.8 million. The Company has delivered approximately $41,400 of this commitment through December 31, 2007. In
addition to the pipeline, Frontier also built and installed lateral gathering lines to eight locations. The remaining commitment on these laterals is $1.3 million, for a total potential
liability of approximately
$2.0 million to be paid by June 2010 if the minimum volumes are not delivered. We currently have not recorded a liability for these commitments as we expect to meet the minimum physical
delivery based on estimated production.

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

Allowance for Doubtful AccountsThe Company routinely assesses the recoverability of all material trade and other receivables
to determine its ability to collect the receivables in full. Many of the Company's receivables are from joint interest owners on properties of which the Company is the operator. Thus, the Company may
have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company's crude oil and natural gas receivables are
collected within two to three months. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of
any reserve may be reasonably estimated (see Note 3).

F-9

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

InventoriesInventories consist principally of tubular goods and production equipment, stated at the lower of weighted-average
cost or market.

Other Property, Plant & EquipmentDepreciation of other office furniture and equipment and computer hardware and
software is provided using the straight-line method based on estimated useful lives ranging from one to seven years.

Oil and Natural Gas PropertiesThe accounting for our business is subject to special accounting rules that are unique to the
oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the successful-efforts method and the full-cost method. There are several
significant differences between these methods. Among these differences is that, under the successful-efforts method, costs such as geological and geophysical ("G&G"), exploratory dry holes and delay
rentals are expensed as incurred whereas under the full-cost method these types of charges are capitalized to their respective full-cost pool. The Company utilizes the
full-cost method of accounting for oil and natural gas properties. In accordance with the full-cost method of accounting, all costs associated with the exploration, development
and acquisition of oil and natural gas properties, including salaries, benefits and other internal costs directly attributable to these activities are capitalized within a cost center. The Company's
oil and natural gas properties are located within the United States of America, which constitutes one cost center. The Company capitalized $4.0 million, $3.0 million, and
$2.6 million of general and administrative costs in 2007, 2006 and 2005, respectively. The Company also
capitalizes a portion of interest expense on borrowed funds related to unproved oil and gas properties. The Company capitalized approximately $7.9 million, $5.3 million, and
$1.9 million of interest costs in 2007, 2006 and 2005, respectively.

In
the measurement of impairment of proved oil and gas properties, the successful-efforts method of accounting follows the guidance provided in SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived
Assets, where the first measurement for impairment is to compare the net book value
of the related asset to its undiscounted future cash flows using commodity prices consistent with management expectations. The full-cost method follows guidance provided in Securities and
Exchange Commission ("SEC") Regulation S-X Rule 4-10, where impairment is determined by the "ceiling test," whereby to the extent that such capitalized costs
subject to amortization in the full cost pool (net of depletion, depreciation and amortization and related deferred taxes) exceed the present value (using 10% discount rate) of estimated future net
after-tax cash flows from proved oil and natural gas reserves adjusted for asset retirement obligations net of salvage value, such excess costs are charged to expense. Once incurred, an
impairment of oil and natural gas properties is not reversible at a later date. A ceiling test impairment could result in a significant loss for a reporting period; however, future depletion expense
would be correspondingly reduced. In accordance with SEC Staff Accounting Bulletin ("SAB") No. 103,Update of Codification of Staff Accounting
Bulletins, derivative instruments qualifying as cash flow hedges are to be included in the computation of limitation on capitalized costs. The Company has applied the
mark-to-market accounting method of accounting since January 1, 2006; therefore, the ceiling test at December 31, 2007 and 2006 was not impacted by the value of
our derivatives. At December 31, 2005, the Company was applying cash flow hedge accounting to its natural gas derivatives, and the period-end price was between the cap and floor
established by the Company's hedge contracts and thus no impact was included in the ceiling test calculation.

Impairment
of oil and natural gas properties is assessed quarterly in conjunction with the Company's quarterly and annual SEC filings. For the third and fourth quarters of 2007, the
Company

F-10

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

elected
to use a pricing date subsequent to the balance sheet date, as allowed by SEC guidelines, to calculate the full-cost ceiling. Using prices as of January 20, 2008, no ceiling
test impairment was required at December 31, 2007. Had the Company used prices in effect as of the balance sheet date, an impairment of $43.8 million ($28.5 million, net of tax)
would have been recorded in the fourth quarter of 2007. The Company recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31,
2006 of $96.9 million ($63.0 million, net of tax), during the third quarter of 2006, as a result of a decline in natural gas prices at the measurement date. This 2006 impairment was
calculated based on prices of $4.18 per MMBtu for natural gas and $62.92 per barrel of crude oil. No ceiling test impairment was required during 2005.

Oil
and natural gas properties are amortized using the unit-of-production method using estimates of proved reserve quantities. Investments in unproved properties
are not amortized until proved reserves associated with the prospects can be determined or until impairment occurs. Unproved oil and natural gas properties consist of the cost of unevaluated
leaseholds, cost of seismic data, exploratory and developmental wells in progress, and secondary recovery projects before the assignment of proved reserves. Oil and natural gas properties include
costs of $34.9 million and
$57.6 million at December 31, 2007 and 2006, respectively, related to unproved property, which were excluded from capitalized costs being amortized. Unproved properties are evaluated
quarterly, and as needed, for impairment on a property-by-property basis. Factors considered by management in its impairment assessment include drilling results by the Company
and other operators, the terms of oil and natural gas leases not held by production, production response to secondary recovery activities and available funds for exploration and development. If the
results of an assessment indicate that an unproved property is impaired, the amount of impairment is added to the proved oil and natural gas property costs to be amortized. In September 2004,
the SEC issued SAB No. 106,Interaction of Statement 143 and the Full Cost Rules,which the Company adopted in the fourth quarter of 2004
with no impact on the Company's financial statements. In accordance with SAB No. 106, the amortizable base used to calculate unit-of-production depletion includes
estimated future development and dismantlement costs, and restoration and abandonment costs, net of estimated salvage values. The depletion rates per Mcfe for the years ended December 31, 2007,
2006 and 2005 were $3.77, $3.51, and $2.43, respectively.

Sales
of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the
relationship between capitalized costs and proved reserves.

Asset Retirement ObligationsThe Company accounts for asset retirement obligations under the provisions of SFAS
No. 143,Accounting for Asset Retirement Obligations,which provides for an asset and liability approach to accounting for Asset Retirement
Obligations ("ARO"). Under this method, when legal obligations for dismantlement and abandonment costs, excluding salvage values, are incurred, a liability is recorded at fair value and the carrying
amount of the related oil and gas properties is increased. Accretion of the liability is recognized each period using the interest method of allocation and the capitalized cost is depleted over the
useful life of the related asset (see Note 7).

Income TaxesThe Company accounts for income taxes under the provisions of SFAS No. 109, Accounting for Income
Taxes, which provides for an asset and liability approach to accounting for income taxes. Effective January 1, 2007, the
Company also applied the provisions of FIN 48 and FSP 48-1 (see Note 16).

F-11

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Earning per ShareThe Company accounts for earnings per share in accordance with SFAS No. 128, Earnings per
Share, which establishes the presentation requirements for earnings per share ("EPS") (see Note 18).

Share-Based CompensationAt December 31, 2007, the Company had a share-based employee compensation plan that included
restricted stock units and stock options issued to employees
and non-employee directors, as more fully described in Note 18. Stock options were last issued in April 2004. The Company accounts for share-based compensation in accordance
with the provisions of SFAS No. 123(R),Share-Based Payment,which requires that the compensation cost relating to share-based payment
transactions be recognized in financial statements. Prior to 2006, the Company accounted for share-based compensation using the intrinsic value recognition and measurement principles detailed in
Accounting Principles Board ("APB") Opinion No. 25,Accounting for Stock Issued to Employeesand related interpretations. Except for certain
repriced options described below, no share-based compensation expense relating to stock option grants was reflected in the Company's consolidated statements of operations for any period presented
prior to 2006, since all options granted under the plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The Company used the Black-Scholes option
calculation model to calculate the disclosures required under SFAS No. 123,Accounting for Stock Based Compensation. In 1999, the Company
repriced certain employee and director stock options. The Company accounted for these repriced stock options in accordance with FASB Interpretation No. 44 ("FIN 44"), Accounting for Certain Transactions involving
Stock Based CompensationAn Interpretation of APB No. 25, which prescribed the variable
plan accounting treatment for repriced options. Under variable plan accounting, compensation expense is adjusted for increases or decreases in the fair market value of the Company's common stock to
the extent that the market value exceeds the exercise price of the option until the options are exercised, forfeited, or expire unexercised. The Company elected to use the modified-prospective method
for adoption of SFAS No. 123(R) and recognized additional compensation expense of $68,937 in 2006. No further expense associated with stock options was recorded in 2007 or is expected to be
recognized unless future awards are granted. The Company has recorded compensation expense associated with the issuance of restricted stock and restricted stock units since the plan was adopted in
1997 and stock or stock units were first granted.

Share-based
compensation for the years ended December 31, 2007, 2006 and 2005 was approximately $3.0 million, $2.0 million and $2.6 million, respectively, of
which $2.4 million, $1.6 million and $2.4 million, respectively, is included in general and administrative expenses ("G&A") and $0.6 million, $0.4 million and
$0.2 million, respectively is capitalized to oil and natural gas properties.

During
the year ended December 31, 2007, 293,800 restricted stock units ("RSUs") were granted. At December 31, 2007, 584,800 RSUs were outstanding, all of which are
classified as equity instruments. No options were granted during the year ended December 31, 2007. During 2007, 7,000 options were exercised and 100 options were forfeited, resulting in 643,600
options outstanding at period end. '

The
following table illustrates the effect on net income and earnings per share information if the Company had applied the fair value recognition provision of SFAS No. 123(R) to
options and restricted stock units granted under our share-based compensation plans in 2005. For the purposes of this pro

F-12

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

forma
disclosure, the value is estimated using a Black-Scholes option-pricing formula and expensed over the option's vesting periods.

Year Ended
December 31,
2005(in thousands, except per share amounts)Net income:As reported

$
33,358Add: share-based employee compensation reported in net income, net of taxes


1,691Deduct: share-based employee compensation under the fair value method for all awards, net of taxes


(822
)Pro forma net income

$
34,227Earnings per share:Basicas reported

$
1.95Basicpro forma


2.00Dilutedas reported


1.87Dilutedpro forma


1.92


Derivatives and Hedging ActivitiesThe Company accounts for its derivative contracts under the provisions of SFAS
No. 133 (as amended). The statement requires that all derivatives be recognized as either assets or liabilities and measured at fair value, and changes in the fair value of derivatives be
reported in current earnings, unless the derivative qualifies for cash flow hedge accounting treatment. If the derivative is designated as a cash flow hedge and the intended use of the derivative is
to hedge the exposure to variability in expected future cash flows, then the changes in the fair value of the derivative instrument will generally be reported in Other Comprehensive Income ("OCI").
These gains and losses on the derivative instrument that are reported in OCI will be reclassified to earnings in the period in which earnings are impacted by the hedged item. If cash flow hedge
accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value and gains and losses
that were accumulated in OCI will be recognized in earnings immediately. During the first quarter of 2006, the Company began applying mark-to-market accounting treatment to all
outstanding derivative contracts. Therefore, the changes in fair value are not deferred through OCI, but rather recorded in revenue immediately as unrealized gains or losses (see Note 9).

Comprehensive IncomeThe Company follows the provisions of SFAS No. 130,Reporting
Comprehensive Income. SFAS No. 130 establishes standards for reporting and presentation of comprehensive income and its components. SFAS No. 130 requires that all
items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other
financial statements. In accordance with the provisions of SFAS No. 130, the Company has presented the components of comprehensive income on the face of the consolidated statements of
comprehensive income. For the year ended December 31, 2005, the only component of other comprehensive income was changes in

F-13

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

fair
value of hedging instruments and reclassifications of hedging gains and losses. This component of other comprehensive income is not applicable in 2007 and 2006 because cash flow hedge accounting
was discontinued in the first quarter of 2006.

Use of EstimatesThe preparation of financial statements in conformity with accounting principles generally accepted in the
United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the
date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates.

Significant
estimates include volumes of oil and gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations,
impairment of undeveloped properties, future income taxes and related assets/liabilities, bad debts, derivatives, contingencies and litigation. Oil and natural gas reserve estimates, which are the
basis for unit-of-production depletion and the ceiling test, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate.
Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices
of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

Concentration of Credit RiskSubstantially all of the Company's accounts receivable result from oil and natural gas sales or
joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk in that these
entities may be similarly affected by changes in economic and other conditions. Historically, the Company has not experienced significant credit losses on such receivables; however, in 2001, the
Company reserved $0.5 million related to non-payments from two purchasers of the Company's oil and natural gas, of which $0.3 million was written off and $0.2 million
was recovered during 2007. In 2007, the Company expensed $0.5 million in accounts receivable, trade related to the ongoing Golden Prairie dispute that the Company no longer felt it could
collect as it had exhausted its efforts on this matter. In 2006, the Company wrote off $1,571 in accounts receivable from joint interest owners. During 2005, the Company recorded $65,157 of bad debt
expense to increase its allowance for outstanding receivables from joint interest owners and wrote off $142,386 in accounts receivable from
joint interest owners. The Company cannot ensure that similar such losses may not be realized in the future.

Recently Issued Accounting PronouncementsIn September 2006, the FASB issued SFAS No. 157, Fair Value Measurements,which provides guidance for using fair value to measure assets and liabilities. The standard also gives expanded information
about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. SFAS No. 157
does not expand the use of fair value in any new circumstances. SFAS No. 157 establishes a fair value hierarchy that prioritizes the information used to develop fair value assumptions. SFAS
No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued a FASB Staff Position ("FSP") on SFAS
No. 157 that permits a one-year delay of the effective date for all non-financial assets and non-financial liabilities, except those that are recognized or
disclosed at fair value in the financial

F-14

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

statements
on a recurring basis (at least annually). The Company will adopt SFAS No. 157 effective January 1, 2008, with the exceptions allowed under the FSP described above and does not
expect any significant impact on its consolidated financial statements, other than expanded disclosures beginning with its Quarterly Report on Form 10-Q for the fiscal quarter ended
March 31, 2008.

In
February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial LiabilitiesIncluding an
Amendment of FAS Statement No. 115. SFAS No. 159 gives companies the option of applying at specified election dates fair value accounting to certain financial
instruments and other items that are not currently required to be measured at fair value. If a company chooses to record eligible items at fair value, the company must report unrealized gains and
losses on those items in earnings at each subsequent reporting date. SFAS No. 159 also prescribes presentation and disclosure requirements for assets and liabilities that are measured at fair
value pursuant to this standard and pursuant to the guidance in SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities (as
amended). SFAS No. 159 will be effective for fiscal year 2008. As the provisions of SFAS No. 159 are applied prospectively, the impact to the Registrants will
depend on the instruments selected for fair value measurement at the time of implementation. The Company is currently determining the impact, if any, that SFAS No. 159 will have on its
consolidated financial statements.

In
December 2007, the FASB issued SFAS No. 141(R),Business Combinations("SFAS No. 141(R)"). SFAS No. 141(R)
expands the definition of transactions and events that qualify as business combinations; requires that the acquired assets and liabilities, including contingencies, be recorded at the fair value
determined on the acquisition date and changes thereafter reflected in revenue, not goodwill; changes the recognition timing for restructuring costs; and requires acquisition costs to be expensed as
incurred. Adoption of SFAS No. 141(R) is required for combinations after December 15, 2008. Early adoption and retroactive application of SFAS No. 141(R) to fiscal years preceding
the effective date are not permitted. However, accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for prior business
combinations will impact tax expense instead of impacting the prior business combination accounting starting January 1, 2009. The Company is currently evaluating the changes provided in SFAS
No. 141(R) and believes it
could have a material impact on the Company's consolidated financial statements if it undertakes a significant acquisition or business combination.

In
December 2007, the FASB issued SFAS No. 160,Noncontrolling Interest in Consolidated Financial Statements("SFAS
No. 160"). SFAS No. 160 re-characterizes minority interests in consolidated subsidiaries as non-controlling interests and requires the classification of minority
interests as a component of equity. Under SFAS No. 160, a change in control will be measured at fair value, with any gain or loss recognized in earnings. The effective date for SFAS
No. 160 is for annual periods beginning on or after December 15, 2008. Early adoption and retroactive application of SFAS No. 160 to fiscal years preceding the effective date are
not permitted. The Company currently does not expect adoption of this statement to have an impact on its consolidated financial statements.

ReclassificationsCertain reclassifications of prior period balances have been made to conform to current reporting practices.

F-15

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3.    ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Below are the components of Accounts Receivable, Joint Interest Owners and Other, as of December 31, 2007 and 2006:

December 31,2007

2006(in thousands)Joint interest owners

$
14,156

$
2,218Other Receivables(1)


307


2Allowance for Doubtful Accounts Receivable (joint interest owners)


(3
)

(3
)Net Accounts Receivable, joint interest owners and other

$
14,460

$
2,217




The
following table sets forth changes in the Company's allowance for doubtful accounts receivable, trade and joint interest owners and other, for the years ended December 31,
2007, 2006 and 2005:

Balance at
Beginning of
Year

Charged to
Costs and
Expenses

Deductions
and Other

Balance at
End of
Year(in thousands)Year ended December 31, 2007:Allowance for doubtful accounts

$
528

$
257

$
(782
)
$
3Year ended December 31, 2006:Allowance for doubtful accounts

$
530

$


$
(2
)
$
528Year ended December 31, 2005:Allowance for doubtful accounts

$
607

$
65

$
(142
)
$
530


4.    OTHER CURRENT ASSETS

Below are the components of other current assets as of December 31, 2007 and 2006:

December 31,2007

2006(in thousands)Prepaid insurance

$
785

$
397Prepayments and deposits to vendors


433


387Prepaid seismic licenses


469


266Drilling advances


485


1,151Other


225


Inventory(1)


1,682


1,758Total other current assets

$
4,079

$
3,959




F-16

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5.    PROPERTY AND EQUIPMENT

At December 31, 2007 and 2006, property and equipment consisted of the following:

December 31,2007

2006(in thousands)Developed oil and natural gas properties

$
1,059,788

$
521,713Unevaluated oil and natural gas properties


34,865


57,577Computer equipment and software


5,085


4,602Other office property and equipment


5,996


2,588Total property and equipment


1,105,734


586,480Accumulated depletion, depreciation and amortization


(388,444
)

(297,023
)Total property and equipment, net

$
717,290

$
289,457


Costs
associated with unproved properties and major development projects related to continuing operations of $34.9 million and $57.6 million as of December 31, 2007
and 2006, respectively, are excluded from amounts subject to amortization.

Year Costs IncurredExcluded
Costs at
December 31,
2007Prior
Years

2005

2006

2007(in thousands)Property acquisition

$
20

$
1,166

$
2,628

$
14,433

$
18,247Exploratory


14


170


4,424


7,091


11,699Capitalized interest


1


26


1,539


3,353


4,919Total Costs Excluded

$
35

$
1,362

$
8,591

$
24,877

$
34,865


The
majority of the evaluation activities are expected to be completed within two to three years. These excluded costs represent unproved properties and major development projects in
which the Company owns a direct interest, including the following:



F-17

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



6.    ACQUISITIONS AND DIVESTITURES

South and southeast Texas asset acquisition in January 2007On November 16, 2006, the
Company entered into two separate purchase and sale agreements (both of which were subsequently amended) with an unrelated privately held company for (A) (i) ownership interests in
certain oil and natural gas properties located in 13 counties in southeast and south Texas, consisting of approximately 150 gross (74 net) producing wells from the private company and eight other
owners who transferred their interests to the private company prior to the closing, (ii) an ownership interest in approximately 17,000 gross (12,250 net) developed acres and 56,000 gross
(16,000 net) undeveloped acres of leasehold, (iii) 25% of the private company's option and leasehold rights and exploration and development rights in an approximate 95 square mile exploration
project area known as the Mission project area, also in south Texas, and (iv) certain gathering facilities and ownership of approximately 13 miles of natural gas gathering pipelines and
related infrastructure serving certain producing assets in southeast Texas ((i) through (iv) collectively referred to as the "South and Southeast Texas Properties"); and (B) working
interest, option and leasehold rights in two exploration ventures in separate areas, primarily in Texas, from the private company (the "Ventures" and collectively with the South and Southeast Texas
Properties, the "Properties"). The combined cash purchase price paid at closing on January 31, 2007 was approximately $379.8 million for the South and Southeast Texas Properties and
$10.0 million for the Ventures (which includes the deposit paid in December 2006). The purchase price for the South and Southeast Texas Properties was adjusted from the base purchase
price of $385 million for, among other things, the results of operations of the South and Southeast Texas Properties between the January 1, 2007 effective date and the January 31,
2007 closing date. Accordingly, the Company's consolidated results of operations include the South and Southeast Texas Properties beginning February 1, 2007. On December 12, 2007 the
Company accepted the final adjusted closing price of $384.4 million, which was adjusted pursuant to the post-closing adjustment provisions of the amended purchase and sale
agreements. The Company financed the purchase price of the South and Southeast Texas Properties through public offerings of common and preferred stock (see Notes 11 and 12) and borrowings under
its credit facility (see Note 10). The Company also capitalized approximately $1.4 million in other direct costs resulting from the acquisition and assumed ARO liabilities of
$0.9 million.

During
the third quarter 2007, the Company elected to terminate one of the two Ventures in south Texas, which was entered into in January 2007. The effective date of termination
for this Venture was October 2, 2007. In exchange for returning all 3-D seismic data covering the area of mutual interest, the privately held company refunded the Company's payments
since January 2007 related to this exploration venture. In October 2007, the Company received $5.5 million, including the $5.0 million initial price paid for the Venture
and $0.5 million in expenses related to the Venture, which were incurred and paid to the privately held company from January to September 2007.

The
following unaudited pro forma results for the year ended December 31, 2006 show the effect on the Company's consolidated results of operations as if the January 2007
Acquisition had occurred on January 1, 2006. The unaudited pro forma results for the year ended December 31, 2007 show the effect on the Company's consolidated results of operations as
if the January 2007 Acquisition had occurred on January 1, 2007. The pro forma results for the 2006 and 2007 periods presented are the result of combining the statement of income for the
Company with the revenues and direct operating expenses of the Properties acquired adjusted for (1) assumption of ARO liabilities and accretion expense for the properties acquired,
(2) depletion expense applied to the adjusted basis of the properties acquired using the purchase method of accounting, (3) depreciation expense for other non-oil and natural
gas assets acquired, (4) interest expense on added borrowings necessary to finance

F-18

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6.    ACQUISITIONS AND DIVESTITURES (Continued)

the
acquisition, (5) amortization of deferred loan costs for new loan costs related to the financing of the acquisition, (6) dividends payable on the 5.75% Series A cumulative
convertible perpetual preferred stock, (7) the related income tax effects of these adjustments based on the applicable statutory rates, and (8) the impact of common and preferred shares
issued in public offerings completed to partially finance the January 2007 Acquisition. The pro forma information is based upon numerous assumptions, and is not necessarily indicative of future
results of operations:

For the Year Ended December 31,2007

2006(unaudited)
(in thousands, except per share amounts)Total revenue

$
166,737

$
213,743Net income (loss)


8,324


(24,358
)Net income (loss) available to common stockholders


90


(32,623
)Net income (loss) per common share:Basic

$


$
(1.15
)Diluted

$


$
(1.15
)


Chapman Ranch Field Acquisition in 2006On December 12, 2006, the Company executed an agreement to acquire certain
working interests in the Chapman Ranch Field in Nueces County, Texas from Kerr-McGee Oil & Gas Onshore LP ("Kerr-McGee"), a wholly owned subsidiary of Anadarko
Petroleum Corporation. In late 2005, the Company acquired non-operated working interests in certain wells in this field, as discussed below. Upon the closing of the Kerr-McGee
acquisition on December 28, 2006, the Company assumed operatorship of Chapman Ranch. The final adjusted purchase price of $25.3 million was financed through borrowings under the
Company's then-existing credit facility.

Chapman Ranch Field Acquisitions in 2005On September 21, 2005, the Company executed two separate and definitive
agreements for the acquisition of (i) the stock of a private company, Cinco Energy Corporation ("Cinco"), whose primary asset is ownership of working interests in oil and natural gas properties
located on the Chapman Ranch Field in Nueces County, Texas (which closed on November 30, 2005) and (ii) additional working interests in the Chapman Ranch Field owned by two other private
companies (which closed October 13, 2005) for an aggregate final purchase price of approximately $74.9 million (of which $46.9 million was attributable to the stock purchase and
$28.0 million was attributable to the working interest asset purchase). The Company allocated approximately $17.5 million of the total purchase price to the unproved property category.
Both purchase prices were subject to adjustment pursuant to the provisions of the applicable agreements.
The Company also agreed to pay the sellers an aggregate adjusted incremental purchase price of $4.8 million (of which $3.9 million was attributable to the stock purchase and
$0.9 million was attributable to the working interest asset purchase) related to the operator obtaining high-cost gas certification, which would provide for severance tax abatements
on the properties acquired. The Company financed the acquisitions through borrowings under its then-existing credit facility.

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

F-19

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6.    ACQUISITIONS AND DIVESTITURES (Continued)

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

$
8,305Current assets


2,470Properties and equipment


53,065Deferred tax liability(1)


(14,945
)Current liabilities


(1,919
)Asset retirement obligation


(64
)Stockholders' equity

$
46,912




DivestituresDuring January 2007, the Company divested a portion of its interest in a Louisiana well for
$1.1 million. In 2006, the Company consummated the divestiture of its Buckeye properties located in Live Oak County, Texas for net proceeds of $0.6 million. During 2005, the Company had
no divestitures of oil and gas properties. Under full cost accounting rules, gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would
significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. Dispositions during 2007, 2006 and 2005 did not significantly alter
the relationship between capitalized costs and proved reserves; therefore, the proceeds from these transactions were recognized as an adjustment of capitalized costs.

7.    ASSET RETIREMENT OBLIGATIONS

In June 2001, the FASB issued SFAS No. 143, which requires that an asset retirement obligation ("ARO") associated with the retirement of a tangible
long-lived asset be recognized as a 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 the related oil and gas properties is increased. The fair value of the ARO asset and liability is measured using expected
future cash outflows discounted at the Company's credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and
the capitalized cost is depleted over the useful life of the related asset.

F-20

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7.    ASSET RETIREMENT OBLIGATIONS (Continued)

The
Company adopted SFAS No. 143 on January 1, 2003, whereby the Company records an abandonment liability associated with its oil and natural gas wells when those assets
are placed in service. The changes to the ARO during the periods ended December 31, 2007 and 2006 are as follows:

For the Year Ended December 31,2007

2006(in thousands)ARO, beginning of year

$
3,371

$
2,767Additional liabilities incurred


1,203


572Liabilities settled


(53
)

(199
)Accretion expense


297


189Revisions


1,816


42ARO, end of year

$
6,634

$
3,371Current portion

$
589

$
213Long-term portion

$
6,045

$
3,158


ARO
liabilities incurred during the year ended December 31, 2007 include obligations assumed for 216 wells that were acquired or successfully drilled during the year and several
non-operated wells that were not previously identified. Liabilities settled during the year ended December 31, 2007 included seven wells that were either plugged or sold. Revisions
to the estimated liability relate to an annual reassessment of the expected cash outflows and assumptions inherent in the ARO calculation.
During 2007, the cost inputs were increased to recognize the increased cost of site restoration and overall increased costs in the industry as a result of commodity price increases.

8.    ACCRUED LIABILITIES

Below are the components of accrued liabilities as of December 31, 2007 and 2006:

As of December 31,2007

2006(in thousands)Accrued capital expenditures

$
8,084

$
6,603Professional services


1,368


1,244Royalties payable


12,377


4,014Lease operating expenses including ad valorem taxes payable


4,291


2,438Preferred stock dividends payable


1,722


Litigation settlement





1,328Other


1,774


1,011Total accrued liabilities

$
29,616

$
16,638


9.    HEDGING AND DERIVATIVE ACTIVITIES

Due to the volatility of oil and natural gas prices, the Company periodically enters into price-risk management transactions (e.g., swaps,
collars and floors) for a portion of its expected oil and natural gas production to seek to achieve a more predictable revenue, as well as to reduce exposure from price

F-21

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9.    HEDGING AND DERIVATIVE ACTIVITIES (Continued)

fluctuations.
While the use of these arrangements may limit the Company's ability to benefit from increases in the price of oil and natural gas, it is also intended to reduce the Company's potential
exposure to adverse price movements. As a result of changes to the Company's forecasted 2008 production and the impact of certain divestitures, both of which have reduced expected production as
compared to that expected at the time we entered into the derivative contracts, the Company currently has approximately 110% and 150% of its anticipated 2008 natural gas and crude oil production,
respectively, covered by derivative contracts. The Company's arrangements, to the extent it enters into any, are intended to apply to only a portion of its expected production and thereby provide only
partial price protection against declines in oil and natural gas prices. None of these instruments are, at the time of their execution, intended to be used for trading or speculative purposes, but may
be deemed as such because of the expected decrease in our 2008 production. These derivative transactions are generally placed with major financial institutions that the Company believes are minimal
credit risks. On a quarterly basis, the Company's management sets all of the Company's price-risk management policies, including volumes, types of instruments and counterparties. These
policies are implemented by management through the execution of trades by the Chief Financial Officer after consultation and concurrence by the President and Chairman of the Board. The Board of
Directors monitors the Company's policies and trades monthly.

All
of these price-risk management transactions are considered derivative instruments and accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities(as
amended). These derivative instruments are intended to hedge the Company's price risk
and may be considered hedges for economic purposes, but certain of these transactions may not qualify for cash flow hedge accounting. All derivative instruments, other than those that meet the normal
purchases and sales exception, are recorded on the balance sheet at fair value and the cash flows resulting from settlement of these derivative transactions are classified in operating activities on
the statement of cash flows. For those derivatives in which mark-to-market accounting treatment is applied, the changes in fair value are not deferred through OCI on the
balance sheet. Rather they are immediately recorded in total revenue on the statement of operations. For those derivative instrument contracts that are designated and qualify for cash flow hedge
accounting, the effective portion of the changes in the fair value of the contracts is recorded in OCI on the balance sheet and the ineffective portion of the changes in the fair value of the
contracts is recorded in total revenue on the statement of operations, in either case, as such changes occur. When the hedged production is sold, the realized gains and losses on the contracts are
removed from OCI and recorded in revenue. While the contract is outstanding, the ineffective gain or loss may increase or decrease until settlement of the contract depending on the fair value at the
measurement dates.

During
the first quarter of 2006, the Company began to apply mark-to-market accounting treatment to all outstanding derivative contracts, whereas cash flow hedge
accounting treatment was applied to natural gas contracts prior to 2006. As a result, the changes in fair value are not deferred through other comprehensive income, but rather recorded in revenue
immediately as unrealized gains or losses. Therefore, unrealized gains and losses on the change in fair value of natural gas contracts between periods may not be comparable. The Company continues to
evaluate the terms of new contracts entered into to determine whether cash flow hedge accounting treatment or mark-to-market accounting treatment will be applied. The Company
has always used mark-to-market accounting treatment for its crude oil contracts.

F-22

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9.    HEDGING AND DERIVATIVE ACTIVITIES (Continued)

For
the years ended December 31, 2007, 2006 and 2005, the Company included in revenue realized and unrealized losses related to its derivative contracts. There was no
ineffectiveness recognized during the years ended December 31, 2005 when cash flow hedge accounting was applied to the Company's natural gas contracts. For the three years ended
December 31, 2007, 2006 and 2005, the Company included in total revenue the following realized and unrealized gains and losses:

For the Year Ended December 31,2007

2006

2005(in thousands)Natural gas collar realized settlements

$
4,513

$
4,699

$
(1,230
)Crude oil collar/swap realized settlements


(935
)




(1,757
)Natural gas collar unrealized change in fair value


(2,060
)

4,686


Crude oil collar/swap unrealized change in fair value


(15,456
)

345


720Gain (loss) on hedging and derivatives

$
(13,938
)
$
9,730

$
(2,267
)


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

|                |       |  |           |  |            |  |            |  |                 |  |              | Fair Value of Outstanding Derivative Contracts as of December 31, |        
|--------------- | ----- |  | --------- |  | ---------- |  | ---------- |  | --------------- |  | ------------ | ----------------------------------------------------------------- | -------
|
|
|
|Natural Gas(1): |       |  |           |  |            |  |            |  |                 |  |              |                                                                   |        
|                | 08/06 |  | Collar(3) |  | 01/01/2007 |  | 12/31/2007 |  | $7.50 - $11.50  |  | 5,000 MMBtu  |                                                                   | $      
|                | 08/06 |  | Collar(3) |  | 01/01/2007 |  | 12/31/2007 |  | $7.50 - $12.00  |  | 5,000 MMBtu  |                                                                   |        
|                | 01/07 |  | Collar    |  | 01/01/2008 |  | 12/31/2008 |  | $7.50 - $9.00   |  | 20,000 MMBtu |                                                                   |        
|                | 01/07 |  | Collar    |  | 01/01/2008 |  | 12/31/2008 |  | $7.50 - $9.00   |  | 10,000 MMBtu |                                                                   |        
|                | 01/07 |  | Collar    |  | 01/01/2008 |  | 12/31/2008 |  | $7.50 - $9.02   |  | 10,000 MMBtu |                                                                   |        
|                | 04/07 |  | Collar    |  | 01/01/2009 |  | 12/31/2009 |  | $7.75 - $10.00  |  | 10,000 MMBtu |                                                                   |        
|                | 10/07 |  | Collar    |  | 01/01/2009 |  | 12/31/2009 |  | $7.75 - $10.08  |  | 10,000 MMBtu |                                                                   |        
|Crude Oil(2):   |       |  |           |  |            |  |            |  |                 |  |              |                                                                   |        
|                | 08/06 |  | Collar    |  | 01/01/2007 |  | 12/31/2007 |  | $70.00 - $87.50 |  | 400 Bbl      |                                                                   |        
|                | 12/06 |  | Swap      |  | 01/01/2007 |  | 12/31/2007 |  | $66.00          |  | 600 Bbl      |                                                                   |        
|                | 12/06 |  | Swap      |  | 01/01/2008 |  | 12/31/2008 |  | $66.00          |  | 1,500 Bbl    |                                                                   |        
|                | 10/07 |  | Collar    |  | 01/01/2009 |  | 12/31/2009 |  | $70.00 - $93.55 |  | 300 Bbl      |                                                                   |        
|                |       |  |           |  |            |  |            |  |                 |  |              |                                                                   |        
|                |       |  |           |  |            |  |            |  |                 |  |              | $                                                                 | (12,329
|                |       |  |           |  |            |  |            |  |                 |  |              |                                                                   |        

---

F-23

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10.    LONG-TERM DEBT

On January 30, 2007, the Company terminated its Third Amended and Restated Credit Agreement (the "Prior Credit Facility"), which it had originally entered
into in March 2004 (effective December 31, 2003). The Prior Credit Facility was scheduled to mature on March 31, 2008 and had a borrowing base of $140.0 million, of which
$129.0 million was outstanding as of January 30, 2007.

On
January 30, 2007, the Company entered into a Fourth Amended and Restated Credit Agreement (the "Agreement") for a new revolving credit facility with Union Bank of California
("UBOC"), as
administrative agent and issuing lender, and the other lenders party thereto. Pursuant to the Agreement, UBOC acts as the administrative agent for a senior, first lien secured borrowing base revolving
credit facility (the "credit facility") in favor of the Company and certain of its wholly-owned subsidiaries in an amount equal to $750 million, of which only $320 million was available
under the borrowing base at the time of closing. The credit facility has a letter of credit sub-limit of $20 million. In connection with the credit facility, the Company paid the
lenders fees in an amount equal to 1.00% of the initial borrowing base established under the credit facility, or $3.2 million, on January 31, 2007. The Company also paid approximately
$0.6 million for certain other administrative fees, legal fees, fronting fees and work fees in connection with the credit facility. The aggregate fees of $3.8 million (of which
$0.1 million was paid in December 2006) were recorded to deferred loan costs and are being amortized over the maturity of the credit facility.

The
credit facility matures on January 31, 2011 and bears interest at LIBOR plus an applicable margin ranging from 1.25% to 2.5% or Prime plus a margin of up to 0.25%, with an
unused commitment fee ranging from 0.50% to 0.25%. At December 31, 2007, the interest rates applied to the Company's outstanding Prime and LIBOR borrowings were 7.250% and 6.900%, respectively.
As of December 31, 2007, $260 million in total borrowings were outstanding under the credit facility. The Company's available borrowing capacity under the credit facility was
$40 million at December 31, 2007. The borrowing base was reduced from $320 million to $300 million during the fourth quarter of 2007. It will be redetermined in the second
quarter of 2008.

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



F-24

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10.    LONG-TERM DEBT (Continued)



Consolidated
EBITDAX is a component of negotiated covenants with our lender and is discussed here as part of the Company's disclosure of its covenant obligations. The credit facility
includes other covenants and events of default that are customary for similar facilities. It is an event of default under the credit facility if the Company undergoes a change in control. "Change in
control," as defined in the credit facility, means any of the following events: (a) any "person" or "group" (within the meaning of Section 13(d) or 14(d) of the Exchange Act) has become,
directly or indirectly, the "beneficial owner" (as defined in Rules 13d-3 and 13d-5 under the Exchange Act, except that a person shall be deemed to have "beneficial
ownership" of all such shares that any such person has the right to acquire, whether such right is exercisable immediately or only after the passage of time, by way of merger, consolidation or
otherwise), of a majority or more of the common stock of the Company on a fully-diluted basis, after giving effect to the conversion and exercise of all outstanding warrants, options and other
securities of the Company (whether or not such securities are then currently convertible or exercisable), (b) during any period of two consecutive calendar quarters, individuals who at the
beginning of such period were members of the Company's Board of Directors cease for any reason to constitute a majority of the directors then in office unless (i) such new directors were
elected by a majority of the directors of the Company who constituted the Board of Directors at the beginning of such period (or by directors so elected) or (ii) the reason for such directors
failing to constitute a majority is a result of retirement by directors due to age, death or disability, or (c) the Company ceases to own directly or indirectly all of the equity interests of
each of its subsidiaries.

In
December 2006, UBOC provided the Company a commitment letter for a $250 million senior, second lien secured bridge loan facility (the "Bridge Loan Facility"). The Bridge Loan
Facility, along with the credit facility, were intended to replace the Company's Prior Credit Facility and to fund the closing of the January 2007 Acquisition (see Note 6) if the Company was
unable to complete one or both of its intended public offerings. Due to the successful completion of the public offering of common stock and 5.75% Series A cumulative convertible perpetual
preferred stock on 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 Bridge Loan Facility, or
$1.3 million, on January 31, 2007, which is included in interest expense.

11.    SHELF REGISTRATION STATEMENT

In the third quarter 2007, the SEC declared effective the Company's registration statement filed with the SEC that registered securities of up to
$500 million of any combination of debt securities, preferred stock, common stock, warrants for debt securities or equity securities of the Company and guarantees of debt securities by the
Company's subsidiaries. Net proceeds, terms and pricing of the offering of securities issued under the shelf registration statement will be determined at the time of the offerings. The shelf
registration statement does not provide assurance that the Company will or could sell any such securities. The Company's ability to utilize the shelf registration statement for the purpose of issuing,
from time to time, any combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities will depend upon, among other things, market conditions and
the existence of investors who wish to purchase the Company's securities at prices acceptable to the Company. As of March 11, 2008, the Company had $500 million available under its shelf
registration statement.

In
January 2007, the Company completed concurrent offerings of 10.925 million shares of its common stock and 2.875 million shares of 5.75% Series A cumulative
convertible perpetual preferred

F-25

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11.    SHELF REGISTRATION STATEMENT (Continued)

stock.
The shares were offered to the public at a price of $13.25 per share of common stock and $50.00 per share of preferred stock. The Company received net proceeds of approximately
$276.5 million from the offerings ($138.1 million from the common offering and $138.4 million from the preferred offering), after deducting underwriting discounts and commissions
and the expenses of the offerings. These proceeds were used to partially finance the January 2007 Acquisition and to refinance the Prior Credit Facility.

Common Stock Offering

Preferred Stock Offering(in thousands, except issue price)Gross Proceeds

$
144,756

$
143,750Underwriting discount


(6,152
)

(4,672
)Other costs of offering


(513
)

(643
)Net Proceeds

$
138,091

$
138,435Shares issued


10,925


2,875Issue price

$
13.25

$
50.00


12.    PREFERRED STOCK

The Company completed the public offering of 2,875,000 shares of its 5.75% Series A cumulative convertible perpetual preferred stock ("Convertible
Preferred Stock") in January 2007.

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

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

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

F-26

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12.    PREFERRED STOCK (Continued)

Ranking.Our Convertible Preferred Stock ranks:



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

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

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

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

Purchase upon fundamental change.If the Company becomes subject to a fundamental change (as defined herein), each holder of
shares of Convertible Preferred Stock will have the right to require the Company to purchase any or all of its shares at a purchase price equal to 100% of the liquidation preference, plus accumulated
and unpaid dividends, to the date of the purchase. The Company will have the option to pay the purchase price in cash, shares of common stock or a combination of cash

F-27

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12.    PREFERRED STOCK (Continued)

and
shares. The Company's ability to purchase all or a portion of the Convertible Preferred Stock for cash is subject to its obligation to repay or repurchase any outstanding debt required to be
repaid or repurchased in connection with a fundamental change and to any contractual restrictions then contained in our debt.

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

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



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

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

F-28

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12.    PREFERRED STOCK (Continued)

In
addition, the Company may generally not, without the approval of the holders of at least 662/3% of the shares of the Convertible Preferred Stock then outstanding:



13.    SUBSEQUENT EVENTS

During the first quarter of 2008, the Company expects to complete the sale of certain non-core assets to various buyers for an aggregate amount of
approximately $16.4 million.

In
late 2007, the Company announced the hiring of a financial advisor to assist its Board of Directors with an assessment of strategic alternatives. On February 7, 2008, the
Company provided an update on the strategic assessment process, which included a thorough review and assessment of the Company's strengths and weaknesses, competitive position and asset base,
reporting that after careful analysis, management and the Board of Directors believed that the best route to maximizing stockholder value at that time was to focus on an assessment of a potential
merger or sale of Edge. The Company is working diligently to explore this alternative. A decision on any particular course of action has not been made and there can be no assurance that the Board of
Directors will authorize any transaction.

14.    COMMITMENTS AND CONTINGENCIES

CommitmentsAt December 31, 2007, the Company was obligated under non-cancelable
operating leases. Following is a schedule of the remaining future minimum lease payments under these leases:

(in thousands)2008

$
1,1672009


1,1682010


1,1752011


1,1712012


1,179Remainder


653Total

$
6,513


Rent
expense for the years ended December 31, 2007, 2006 and 2005 was approximately $0.9 million, $0.7 million, and $0.7 million, respectively.

As
described in Note 2, the Company has natural gas delivery commitments to Frontier. Management believes the Company can meet its delivery commitments based on estimated
production.

F-29

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14.    COMMITMENTS AND CONTINGENCIES (Continued)

This
contract is not considered a derivative, but has been designated as an annual sales contract under SFAS No. 133 (as amended).

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

Wade and Joyce Montet, et al., v. Edge Petroleum Corp of Texas, et al., consolidated with Rolland L. Broussard, et al., v. Edge Petroleum Corp of
Texas, et al.This was a consolidated suit, filed in state court in Vermilion Parish, Louisiana in September 2003. Plaintiffs were mineral/royalty
owners under the Norcen-Broussard No. 1 and 2 wells, Marg Tex Reservoir C, Sand Unit A (Edge's old
Bayou Vermilion Prospect). They claimed the operator at the time, Norcen Explorer, now Anadarko E&P Company ("Anadarko"), failed to "block squeeze" the sections of the No. 2 well, as a prudent
operator, according to their allegations, would have done, to protect the gas reservoir from being flooded with water from adjacent underground formations. Plaintiffs further alleged Norcen Explorer
was negligent in not creating a field-wide unit to protect their interests. The allegations related to actions taken beginning in the early 1990's. Plaintiffs named the Company and other
working interest owners in the leases as defendants, including Norcen Explorer's successors in interest, Anadarko. Plaintiffs originally sought damages, including interest, as high as
$63 million for lost royalties and damages due to alleged devaluation of their mineral and property interests, plus attorneys' fees. Of the 18.75% after-payout working interest 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 interest owners who hold the remainder of the 18.75% working interest as third-party defendants in this case. These third-parties consist, for the most part, of partnerships that are
directly or indirectly controlled by John Sfondrini, a director of the Company, and hold an aggregate 14.7% working interest (the "Sfondrini Partnerships"). Vincent Andrews, also a director of the
Company, owns a minority interest in the corporate general partner of one of the partnerships. The Sfondrini Partnerships consist of (1) Edge Group Partnership, a general partnership composed
of limited partnerships of which Mr. Sfondrini and a company controlled by Mr. Sfondrini are general partners; (2) (A) Edge Option I Limited Partnership, (B) Edge Option 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, 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 party defendants that the Company has sought to join in the case, and these partnerships have for the
most part filed answers denying any liability to the Company.

Broussard Plaintiff Settlement.

On December 19, 2006, the Company, along with the other defendants in this suit, reached a settlement agreement with the Broussard Plaintiffs in full
settlement of their 72% of the total claims made in this consolidated action. This settlement 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' share totaled $1,109,759. The settlement with the Broussard Plaintiffs was

F-30

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14.    COMMITMENTS AND CONTINGENCIES (Continued)

finalized
on February 1, 2007, and the defendants and the third-party defendants including the Sfondrini Partnerships were released from all claims by the Broussard Plaintiffs.

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



In
the purchase and sale transaction between us and the Sfondrini Partnerships, BV Partners Limited Partnership, whose 2.48% share of the Broussard settlement amount was $186,000
(as determined by the Company and Mr. Sfondrini on behalf of the BV Partners Limited Partnership), did not sell any assets to the Company and did not have sufficient funds to satisfy its
share of the settlement amount. In addition, the Edge Option I, II and III Limited Partnerships did not have sufficient assets to satisfy their respective .34%, .34% and 2.25% shares of the settlement
amount, which the Company and Mr. Sfondrini determined to be $25,750, $25,750 and $169,102, respectively. The shortfall amounts of Edge Option I, II and III Limited Partnerships were, net of
assets that they sold to the Company, determined by the Company and Mr. Sfondrini to be $24,333, $24,333 and $163,276, respectively. As a result, Edge Group Partnership sold additional
properties (over the amount necessary to fund its portion of the settlement) to the Company at fair market value in an amount sufficient to allow it to have proceeds from such sale to fund BV
Partners Limited Partnership's share of the settlement and the remaining shortfall amounts owed by Edge Option I, II and III. In return, BV Partners and Edge Option I, II and III contributed
all of their interest in the Bayou Vermilion Prospect leases and the Trahan No. 3 well located thereon to Edge Group Partnership. The fair market value of these interests contributed to Edge
Group by BV Partners Limited Partnership and Edge Option I, II and III were determined by the Company and Mr. Sfondrini on behalf of such partnerships to be $27,793, $3,847, $3,847 and
$25,263, respectively.

The
valuations of the interests of the Sfondrini Partnerships purchased by the Company and the interests contributed to Edge Group Partnership by BV Partners and Edge Option I, II
and III were made at an agreed value, using a PV10 model and assuming $7.50/MMBtu gas and $60/BBl oil, which the Company believed represented current pricing levels for oil and gas properties at the
time, and were agreed to by the Company and Mr. Sfondrini, on behalf of the Sfondrini Partnerships.

F-31

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14.    COMMITMENTS AND CONTINGENCIES (Continued)

Montet Plaintiff Settlement.

The Company and the other oil company defendants participated in a mediation regarding the remaining claims in this lawsuit with the Montet plaintiffs on
May 10, 2007. All remaining claims were settled for a total agreed payment to the Montet plaintiffs of $3.5 million. The Company's and the Sfondrini Partnerships' share of the settlement
amount were $118,333 and $502,917, respectively, for a total of $621,250, which amounts were paid by insurance. As part of the settlement, Mid-Continent Casualty Company and one other
insurer agreed to cover and pay the full share of the Montet settlement amount attributable to the Company and the Sfondrini Partnerships in return for mutual releases under the policies involved and
for a joint dismissal of all claims asserted by the parties in the suit for declaratory judgment filed by Mid-Continent against the Company and the Sfondrini Partnerships in federal
district court in Houston. Also as part of the settlement, the Company reimbursed the Sfondrini Partnerships for certain attorneys' fees in the amount of $62,500. The settlement with the Montet
plaintiffs was finalized in writing in June 2007, all defendants have paid their respective shares of the amounts owed, and the court entered an order to dismiss on August 3, 2007. A final
judgment dismissing all claims with prejudice was filed on June 29, 2007 in the related Mid-Continent suit for declaratory judgment in federal district court in Houston.

David Blake, et al. v. Edge Petroleum CorporationOn September 19, 2005, David Blake and
David Blake, Trustee of the David and Nita Blake 1992 Children's Trust filed suit against the Company in state district court in Goliad County, Texas alleging breach of contract for failure and
refusal to transfer overriding royalty interests to plaintiffs in several leases in Goliad County, Texas and failure and refusal to pay monies to Blake pursuant to such overriding royalty interests
for wells completed on the leases. The plaintiffs seek relief of (1) specific performance of the alleged agreement, including granting of overriding royalty interests by the Company to Blake;
(2) monetary damages for failure to grant the overriding royalty interests; (3) exemplary damages for his claims of business disparagement and slander; (4) monetary damages for
tortuous interference; and (5) attorneys' fees and court costs. Venue of the case was transferred to Harris County, Texas by agreement of the litigants. The Company has served plaintiffs with
discovery and has filed a counterclaim and an amended counterclaim joining various related entities that are controlled by plaintiffs. In addition, plaintiffs have filed an amended complaint alleging
claims of slander of title and tortuous interference related to its alleged right to receive an overriding royalty interest from a third party. Plaintiffs currently have on file an amended motion for
summary judgment, to which the Company has filed a response. In addition, the Company has filed a motion for summary judgment on the plaintiffs' case. In December 2006, the court denied the Company's
motion for summary judgment. The court has not ruled on Blake's motion. In November 2007, the Company filed a separate motion for summary judgment based on the statute of frauds; the court has not
ruled on this separate motion. The trial, originally scheduled to begin September 10, 2007, and reset for March 3, 2008, has been continued until August 20, 2008. Discovery in the
case has commenced and is continuing. The Company has responded aggressively to this lawsuit, and believes it has meritorious defenses and counterclaims.

Diana Reyes, et al. v. Edge Petroleum Operating Company, Inc., et al.On January 8,
2008, the Company was served with a wrongful death action filed in Hidalgo County, Texas. Plaintiffs allege negligence and gross negligence resulting from a fatality accident at the State
B-12 well site, on the Company's Bloomberg Flores lease in Starr County, Texas. The plaintiffs are the widow and minor children of Mr. Reyes, who was killed in a one-car
fatality accident on August 5, 2007. Mr. Reyes was an employee of a vendor of the Company, Payzone Logging. No specific amount of damages has been

F-32

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14.    COMMITMENTS AND CONTINGENCIES (Continued)

alleged
to date; plaintiffs are asserting damages from loss of companionship, pecuniary loss, pain and mental anguish, loss of inheritance and funeral and burial expenses. The Company may have
insurance coverage for all or part of this claim. The Company's insurance carrier has retained local counsel in McAllen, Texas to represent the Company in this matter. The Company filed an answer on
January 30, 2008 denying plaintiffs' allegations and asserting defenses. The Company has not established a reserve with respect to this claim and it is not possible to determine what, if any,
the Company's ultimate exposure might be in this matter. The Company will continue to respond aggressively to this lawsuit, and believes that it has meritorious defenses.

15.    SALES TO MAJOR CUSTOMERS AND OPERATORS

In accordance with SFAS No. 131,Disclosures about Segments of an Enterprise and Related Information,
public business enterprises are required to report financial and other information about operating segments of the entity. Operating segments are defined as components of an enterprise that engage in
activities from which it may earn revenues and incur expenses for which separate operational financial information is available and is regularly evaluated by the chief decision maker for the purpose
of allocating resources and assessing performance. Segment reporting is not applicable to the Company, as it has a single company-wide management team that administers all properties as a
whole rather than by discrete operating segments. The Company tracks only basic operational data by area and does not maintain complete separate financial statement information by area. The Company
measures financial performance as a single enterprise and not on an area-by-area basis. Throughout the year, the Company allocates capital resources on a
project-by-project basis, across the entire asset base to maximize profitability without regard to individual areas or segments.

SFAS
No. 131 also establishes standards for disclosures about major customers. The Company sold natural gas and crude oil production representing 10% or more of its total revenues
for the years ended December 31, 2007, 2006, and 2005 as listed below:

For the Year Ended December 31,Purchaser2007

2006

2005Integrys Energy Services, Inc.

22
%
*

*Kinder Morgan

20
%
37
%
29
%Gulfmark Energy, Inc.

11
%
5
%
6
%Copano Field Services

5
%
10
%
17
%ChevronTexaco Inc.

4
%
12
%
18
%Kerr-McGee Oil & Gas

*

10
%
*






F-33

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15.    SALES TO MAJOR CUSTOMERS AND OPERATORS (Continued)

In the exploration, development and production business, production is normally sold to relatively few customers. A significant portion of the Company's sales are
made on its behalf by the operators of the properties and therefore these entities may be listed above. Substantially all of the Company's customers are concentrated in the oil and gas industry and
revenue can be materially affected by current economic conditions and the price of certain commodities such as natural 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 fact that alternate purchasers are readily available, the Company believes that the loss of any of our major purchasers would not have
a long-term material adverse effect on its operations.

16.    INCOME TAXES

Income tax expense (benefit), including deferred amounts, is summarized as follows:

2007

2006

2005(in thousands)CurrentFederal

$


$
51

$
327State


10





Total Current


10


51


327DeferredFederal


3,474


(21,959
)

17,751State


249


333


Total Deferred


3,723


(21,626
)

17,751TOTAL

$
3,733

$
(21,575
)
$
18,078


Total
income taxes differed from the amounts computed by applying the statutory income tax rate to income before income taxes. The sources of these differences are as follows:

2007

2006

2005(in thousands)Income (Loss) Before Income Taxes

$
10,305

$
(62,836
)
$
51,436Statutory tax rate


35
%

35
%

35
%Tax computed on statutory rate

$
3,607

$
(21,993
)
$
18,003Adjustments resulting from:State income taxes (net of federal income tax benefit)


(209
)

333


Change in valuation allowance


468





Expenses not deductible for tax purposes and other


(133
)

85


75Total income tax expense (benefit)

$
3,733

$
(21,575
)
$
18,078Effective tax rate


36.2
%

34.3
%

35.2
%


F-34

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16.    INCOME TAXES (Continued)

The
effect of stock-based compensation expense for tax purposes in excess of or less than amounts recognized for financial accounting purposes was recorded directly to stockholders'
equity in the amounts of approximately $(217,100), $461,900 and $507,300 for 2007, 2006 and 2005, respectively.

Deferred
income taxes reflect the tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts calculated
for income tax purposes in accordance with SFAS No. 109. Under this method, future income tax assets and liabilities are determined based on the "temporary differences" between the accounting
basis and the income tax basis of the Company's assets and liabilities 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 as of December 31, 2007 and 2006 are as follows:

As of December 31,2007

2006(in thousands)Deferred tax liabilitycurrent:Price-risk management liability

$


$
(1,816
)Deferred tax assetcurrent:Price-risk management asset


4,315


Compensation cost


1,222


894Expenses not currently deductible for tax purposes


238


289Other


43


200Total deferred tax assetcurrent


5,818


1,383Net deferred tax asset (liability)current

$
5,818

$
(433
)Deferred tax liabilitylong-term:Book basis of oil and natural gas properties in excess of tax basisFederal & State

$
(75,002
)
$
(37,807
)Deferred tax assetlong-term:Net operating loss carryforwardFederal


51,262


25,956Net operating loss carryforwardStates


1,844


Accretion on ARO


344


246Federal alternative minimum tax credits


497


497Other


197


197Deferred tax asset before valuation allowance


54,144


26,896Valuation allowance


(468
)

Total deferred tax asset


53,676


26,896Net deferred tax liabilitylong-term

$
(21,326
)
$
(10,911
)


Total
deferred taxes at December 31, 2007 and 2006 include state deferred taxes of approximately $0.6 million and $0.3 million, respectively. The valuation allowance
recorded during 2007 relates to state NOL carryforwards discussed below and is included in the net state deferred tax amount of approximately $0.6 million. Also included in the net state
deferred tax assets is a credit carryforward in

F-35

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16.    INCOME TAXES (Continued)

Texas
which arose as a result of a change in tax law from a franchise tax base to a margin tax regime which is treated as an income tax for purposes of SFAS No. 109. The Texas NOL carryforward
under the franchise system is converted into a tax credit which net of federal benefit is approximately $1.0 million which is creditable from 2008 through 2027. An asset was recorded in 2007 as
the Company considers it more likely than not to be utilized over the twenty year carryforward period.

Tax
carryforwards at December 31, 2007, which are available for utilization on future income tax returns, are as follows:

Year of Expiration

Domestic

State(in thousands)2008

$


$
272009





2182010





1062011





7802012


631


3222013





402014





72017





212018


7,032


802019


4,451


9992020


8,046


2,2672021


10,711


7,3992022


9,218


2,2182023


22,045


1,2112024


3,276


1,1922025


5,407


7552026


6,869


1,3602027


68,776


168Net operating loss

$
146,462

$
19,170


The
Company believes that it is more likely than not that it will utilize all of the NOL's in connection with federal income taxes generated in the future and that it is
more likely than not that it will utilize all state NOL carryforwards with the exception of the Louisiana NOL. A valuation allowance was recorded for the net Louisiana NOL carryforward. The estimated
NOL's presented herein assume that certain items, primarily intangible drilling costs, have been written off for tax purposes in the current
year. However, the Company has not made a final determination if an election will be made to capitalize all or part of these items for tax purposes in the future. The Company has an Alternative
Minimum Tax credit carryforward at December 31, 2007 of $496,500 which does not expire. The Company also has a Texas NOL credit carryforward as discussed above.

The
Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. The Company's tax periods are open with the exception of Texas which is
audited through the 2003 report years. The Texas Comptrollers Office began an audit of the 2004 through 2007 report years during the latter part of 2007. Initial fieldwork is in process and is
expected to be

F-36

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16.    INCOME TAXES (Continued)

completed
in 2008. No adjustments have been proposed. The Company believes that any potential adjustments will not be material to its financial position.

In
June 2006, the FASB issued FIN 48,Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement
No. 109, which clarifies the accounting for uncertainty in income taxes recognized in accordance with SFAS No. 109,Accounting for Income
Taxes. As a result of the adoption of FIN 48 on January 1, 2007, the Company recognized a liability of $534,035 which was a reduction in the January 1,
2007 retained earnings balance. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

Balance at January 1, 2007

$
534Additions based on tax positions related to the current year


Additions for tax positions of prior years


Reductions for tax positions of prior years


Settlements


Balance at December 31, 2007

$
534


The
amount recorded does not include interest as the anticipated adjustments more likely than not will result in no current tax due as a result of NOL carryovers. All of the amounts of
unrecognized tax benefits reported affect the effective tax rate through deferred tax accounting.

FIN 48
prescribes a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a
measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon ultimate settlement. If it is not more likely
than not that the benefit will be sustained on its technical merits, no benefit will be recorded. FIN 48 also requires that the amount of interest expense to be recognized related to uncertain
tax positions be computed by applying the applicable statutory rate of interest to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken
or expected to be taken in a tax return. The Company also adopted FSP FIN 48-1 as of January 1, 2007, which provides that a company's tax position will be considered settled
if the taxing authority has completed its examination, the company does not plan to appeal, and it is remote that the taxing authority would reexamine the tax position in the future. The Company had
no reserves prior to adoption at January 1, 2007. The Company recognizes interest and penalties related to unrecognized tax benefits in tax expense. However as stated above, the Company accrued
no interest or penalties at December 31, 2007.

17.    EMPLOYEE BENEFIT PLANS

Effective July 1, 1997, the Company established a defined-contribution 401(k) Savings & Profit Sharing Plan Trust (the "Plan") covering employees of
the Company who are age 21 or older. The Company's matching contributions to the Plan are discretionary. For the years ended December 31, 2007, 2006 and 2005, the Company contributed
approximately $562,000, $480,300, and $176,500, respectively, to the Plan. In 2006, the Company increased the percentage of employee contributions that it matches, which accounts for the significant
increase between 2005 and 2006.

F-37

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18.    EQUITY AND STOCK PLANS

Public Offerings 2007In connection with two concurrent public offerings in January 2007, the Company
issued approximately 2.9 million shares of preferred stock and approximately 10.9 million shares of common stock at gross prices of $50.00 and $13.25 per share, respectively. These
offerings generated net proceeds to us, after underwriters' fees and direct costs of the offering, of $276.5 million. These shares were issued to generate funds to partially finance the January
2007 Acquisition (see Note 6).

Public Offering 2004In connection with a public offering on December 21, 2004, the Company issued 3.5 million
shares of common stock at a gross 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 $47.8 million.
These shares were issued to generate funds to finance the Contango Asset Acquisition that was completed December 29, 2004. In January 2005, the underwriters exercised their overallotment option
for 0.5 million additional shares of common stock, resulting in an additional $7.2 million of net proceeds to the Company.

Share-Based CompensationThe Company established the Incentive Plan of Edge Petroleum Corporation (the "Incentive Plan") in
conjunction with its initial public offering in March 1997. The Incentive Plan is discretionary and provides for the granting of awards, including options for the purchase of the Company's common
stock and for 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 to date
vest over periods of 2 to 4 years. The Company amended the Incentive Plan (i) in December 2003 to increase the shares available under the plan from 1.2 million shares to
1.7 million shares and (ii) in June 2006 to increase the number of shares available under the Plan from 1.7 million shares to 2.2 million shares. Of the aggregate
2.2 million shares of common stock reserved for grants under the Incentive Plan, 243,877 shares were available for future grants at December 31, 2007. The following nonqualified stock
option awards and restricted stock unit grants were made under the Incentive Plan during each of the years indicated below:

|                            |  | Number Granted |  | Market Value on Date of Grant
|--------------------------- |  | -------------- |  | -----------------------------
|Options Awards:             |  |                |  |                              
|2007                        |  |               |  |                             
|2006                        |  |               |  |                             
|2005                        |  |               |  |                             
|Restricted Stock Awards(1): |  |                |  |                              
|2007                        |  | 272,640        |  | $5.92 to $17.59              
|2006                        |  | 326,280        |  | $16.42 to $32.40             
|2005                        |  | 131,640        |  | $14.02 to $25.12             

---

As
a component of his employment agreement with the Company, John Elias, CEO and Chairman of the Board, has been granted option awards and a restricted stock award outside of the
Incentive Plan. Mr. Elias has also been granted options and restricted stock under the Incentive Plan. The options vest and become exercisable over a two year period subsequent to issue. The
restricted stock is

F-38

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18.    EQUITY AND STOCK PLANS (Continued)

issued
over three to four years in accordance with the award's vesting schedule. Compensation expense is amortized over the vesting period and offset to additional paid in capital ("APIC"). The
amortization of compensation expense related to this award is included in general and administrative expenses on the consolidated statement of operations. Below is a summary of options and 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            
|                     | 01/03/2000 |                    | 50,000  |                | $ | 3.16            
|                     | 01/03/2001 |                    | 50,000  |                | $ | 8.88            
|                     | 01/03/2002 |                    | 50,000  |                | $ | 5.18            
|                     | 04/02/2002 |                    | 24,000  |                | $ | 5.59            
|                     | 01/23/2003 |                    | 50,000  |                | $ | 3.88            
|                     | 04/01/2004 |                    | 37,000  |                | $ | 13.99           
|Restricted Stock(2): |            |                    |         |                |   |                 
|                     | 04/02/2001 |                    | 14,000  |                |   |                 

---

Effective
January 1, 2006, the Company adopted SFAS No. 123(R) utilizing the modified prospective approach. Prior to the adoption of SFAS No. 123(R), the Company
accounted for stock option grants in accordance with APB No. 25 using the intrinsic value method, and accordingly, recognized no compensation expense for stock option grants. In 1999, the
Company repriced certain employee and director stock options. The Company accounted for these repriced stock options in accordance with FIN 44 which prescribed the variable plan accounting
treatment for repriced options. Under variable plan accounting, compensation expense is adjusted for increases or decreases in the fair market value of the Company's common stock to the extent that
the market value exceeds the exercise price of the option until the options are exercised, forfeited, or expire unexercised.

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

F-39

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18.    EQUITY AND STOCK PLANS (Continued)

Share-based
compensation costs for the years ended December 31, 2007, 2006 and 2005 were:

Year Ended December 31,2007(1)

2006(1)

2005(2)(3)(in thousands)Stock options

$


$
69

$
Repriced stock options(2)








1,628Restricted stock units


3,004


1,908


974Total share-based compensation

$
3,004

$
1,977

$
2,602




The
Company receives a tax deduction for certain stock options exercised during the period the options are exercised, generally for the excess of the price at which the options are sold
over the exercise prices of the options. In addition, the Company receives a tax deduction for the compensation element of restricted stock grants that vest during the period, which is the vesting
share price multiplied by the number of shares vesting. SFAS No. 123(R) requires that these excess tax benefits be reported in the consolidated statement of cash flows as financing activities.
SFAS No. 123(R) provides that the excess tax benefit and credit to APIC for the windfall should not be recorded until the deduction reduces income taxes payable. Because the Company is in a net
operating loss ("NOL") position for tax purposes, and does not have taxes payable at this time, it has not realized a tax benefit from the deduction. Therefore, the Company excludes
these deductions from the windfall pool and does not present the tax benefits from the exercise of stock options as financing activities, but expects that certain amounts of windfall will be credited
to APIC in future periods when the NOL carryforwards are utilized to reduce taxes payable.

Stock Options

There have been no stock option grants since 2004. For future grants, the Company expects to use the Black-Scholes option pricing model to estimate the fair value
of stock options which requires the Company to make the following assumptions:



F-40

---





EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18.    EQUITY AND STOCK PLANS (Continued)

The
assumptions above are based on multiple factors, including historical exercise patterns of employees in relatively homogenous groups with respect to exercise and
post-vesting employment termination behaviors, expected future exercising patterns for these same homogeneous groups and the implied volatility of our stock price.

In
addition, the Company estimates a forfeiture rate at the inception of the option grant based on historical data and adjusts this prospectively as new information regarding forfeitures
becomes available.

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

A
summary of activity associated with the Company's stock options during the last three years follows:

|                                      |                                  | Number of
Shares |         | Weighted
Average Exercise
Price |   | Weighted
Average
Remaining
Contract Life |  | Aggregate
Intrinsic Value
|------------------------------------- | -------------------------------- | ---------------- | ------- | ------------------------------- | - | ---------------------------------------- |  | -------------------------
|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               
|                                      |                                  |                  |         |                                 |   |                                          |  |                          
|                                      | Exercisable, end of period       |                  | 685,450 |                                 |   | 5.35                                     |  | 4.55 years               
|                                      |                                  |                  |         |                                 |   |                                          |  |                          
|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               
|                                      |                                  |                  |         |                                 |   |                                          |  |                          
|                                      | Exercisable, end of period       |                  | 650,700 |                                 | $ | 5.82                                     |  | 3.92 years               
|                                      |                                  |                  |         |                                 |   |                                          |  |                          
|For the Year Ended December 31, 2007: |                                  |                  |         |                                 |   |                                          |  |                          
|                                      | Outstanding, beginning of period |                  | 650,700 |                                 |   | 5.82                                     |  |                          
|                                      | Exercised                        |                  | (7,000  | )                               |   | 6.01                                     |  |                          
|                                      | Forfeited                        |                  | (100    | )                               |   | 13.50                                    |  |                          
|                                      |                                  |                  |         |                                 |   |                                          |  |                          
|                                      | Outstanding, end of period       |                  | 643,600 |                                 |   | 5.82                                     |  | 2.88 years               
|                                      |                                  |                  |         |                                 |   |                                          |  |                          
|                                      | Exercisable, end of period       |                  | 643,600 |                                 | $ | 5.82                                     |  | 2.88 years               
|                                      |                                  |                  |         |                                 |   |                                          |  |                          

The
fair value of options was measured at the date of grant using the Black-Scholes option-pricing model. There were no options granted for the years ended December 31, 2007, 2006
and 2005. There were 100 options forfeited for the year ended December 31, 2007 and none for the years ended December 31, 2006 and 2005.

F-41

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18.    EQUITY AND STOCK PLANS (Continued)

The
Black-Scholes option valuation model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. In addition,
option valuation models require the input of highly subjective assumptions including the expected stock price volatility. The Company's stock options have characteristics significantly different for
those of traded options and because changes in the subjective input assumptions can materially affect the fair value estimate, it is management's opinion that the valuations afforded by the existing
models are different from the value that the options would realize if traded in the market.

A
summary of additional information related to options outstanding as of December 31, 2007 follows:

|All Options   |  | Options Exercisable
|------------- |  | -------------------
|
|$3.00 - $3.88 |  | 119,500            
|$4.22         |  | 200,000            
|$5.18 - $5.73 |  | 155,500            
|$7.06 - $7.58 |  | 68,600             
|$8.88         |  | 50,000             
|$13.99        |  | 50,000             



In addition to stock options, the Company issues restricted stock and restricted stock units. For awards issued to date, shares of common stock associated with
the restricted stock awards will be issued, subject to continued employment, ratably over three or four years in accordance with the award's vesting schedule, beginning on the first or second
anniversary of the date of grant. Compensation expense from restricted stock and restricted stock units is amortized over the vesting period and offset to APIC. The share-based expense for these
awards was determined based on the market price of the Company's stock at the date of grant applied to the total number of shares that were anticipated to fully vest and then amortized over the
vesting period. As of December 31, 2007, the Company had unamortized share-based compensation of $5.9 million associated with these awards. The cost is expected to be recognized over a
weighted-average period of approximately two years. The total fair value of shares vested during the year ended December 31, 2007 was $1.8 million. Upon adoption of SFAS
No. 123(R), the Company recorded an immaterial cumulative effect of change in accounting principle as a result of the change in policy from recognizing forfeitures as they occur to recognizing
expense based on its expectation of the awards that will vest over the requisite service period for its restricted stock and restricted stock unit awards. This amount was recorded as compensation cost
in general and administrative expenses in the consolidated statement of operations.

F-42

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18.    EQUITY AND STOCK PLANS (Continued)

A
summary of the status of the unvested shares of restricted stock and changes during 2007, 2006 and 2005 is presented below:

Number of
Unvested
Restricted
Shares

Weighted
Average
Grant-Date
Fair ValueUnvested shares as of January 1, 2007

436,624

$
18.43Granted

293,770

$
13.12Vested

(105,063
)
$
19.23Forfeited

(40,549
)
$
16.07Unvested shares as of December 31, 2007

584,782

$
15.78Unvested shares as of January 1, 2006

218,954

$
14.90Granted

333,600

$
19.32Vested

(98,720
)
$
13.14Forfeited

(17,210
)
$
21.02Unvested shares as of December 31, 2006

436,624

$
18.43Unvested shares as of January 1, 2005

147,785

$
10.49Granted

152,244

$
17.01Vested

(59,295
)
$
9.55Forfeited

(21,780
)
$
14.29Unvested shares as of December 31, 2005

218,954

$
14.90


The
aggregate intrinsic value of restricted stock vested during 2007 was approximately $1.4 million.

Computation of Earnings per ShareThe Company accounts for earnings per share in accordance with SFAS
No. 128, which establishes the requirements for presenting earnings per share ("EPS"). SFAS No. 128 requires the presentation of "basic" and "diluted" EPS on the face of the statement of
operations. Basic EPS amounts are calculated using the weighted average number of common shares outstanding during each period. Diluted EPS assumes the exercise of all stock options, warrants and
convertible securities having exercise prices less than the average market price of the common stock during the periods, using the treasury stock method.

Diluted
EPS also includes the effect of convertible securities by application of the "if-converted" method. Under this method, if an entity has convertible preferred stock
outstanding, the preferred dividends applicable to the convertible preferred stock are added back to the numerator. The convertible preferred stock is assumed to have been converted at the beginning
of the period (or at time of issuance, if later) and the resulting common shares are included in the denominator of the EPS calculation. In applying the if-converted method, conversion is
not assumed for purposes of computing diluted EPS if the effect would be anti-dilutive. During 2007, conversion of the convertible preferred

F-43

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18.    EQUITY AND STOCK PLANS (Continued)

stock
is not assumed because the effect would be anti-dilutive. The following tables present the computations of EPS for the periods indicated.

|                                                                            |  | Year Ended December 31, |       
|--------------------------------------------------------------------------- |  | ----------------------- | ------
|
|
|
|Net income (loss)                                                           |  | $                       | 6,572 
|Less: Preferred stock dividends                                             |  |                         | (7,577
|                                                                            |  |                         |       
|Basic EPS                                                                   |  |                         |       
|Net income (loss) available to common stockholders                          |  |                         | (1,005
|Effect of dilutive securities:                                              |  |                         |       
|Restricted stock units                                                      |  |                         |      
|Common stock options                                                        |  |                         |      
|Convertible preferred stock                                                 |  |                         |      
|                                                                            |  |                         |       
|Diluted EPS                                                                 |  |                         |       
|Net income (loss) available to common stockholders plus assumed conversions |  | $                       | (1,005
|                                                                            |  |                         |       

---

Associated with the exercise of stock options, the Company received a tax benefit of approximately $461,900 and $507,300 in 2006 and 2005,
respectively. During 2007, the Company recorded a charge associated with the exercise of stock options of approximately $217,100. The tax benefit or charge is recorded as an increase or decrease in
additional paid-in capital.

19.    RELATED PARTY TRANSACTIONS

The transactions described below were with affiliates, and it is possible that the Company would have obtained different terms from a truly unaffiliated
third-party. In addition, see Note 14 regarding certain disputes with entities involving Mr. Sfondrini (a director of the Company).

Affiliates' Ownership in ProspectsEdge Group Partnership, a Connecticut general partnership composed of the three Connecticut
limited partnerships (Edge I Limited Partnership, The Edge II Limited Partnership, and The Edge III, Limited Partnership) whose general partners are Mr. Sfondrini and a corporation wholly-owned
by him; Edge Holding Company, L.P., a limited partnership of which Mr. Sfondrini and a corporation wholly owned by him are the general partners; Edge Option I Limited Partnership, Edge
Option II Limited Partnership and Edge Option III Limited Partnership are limited partnerships whose general partners are Mr. Sfondrini and a corporation controlled by him; Andex Energy
Corporation and Texedge Energy Corporation, corporations of which Mr. Andrews (a director of the Company) is an officer and members of his immediate family hold ownership interests,

F-44

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19.    RELATED PARTY TRANSACTIONS (Continued)

Mr. Raphael
(a former director of the Company), and Essex II Joint Venture, own certain working interests in the Company's Nita and Austin Prospects and certain other wells and prospects
operated by the Company. These working interests aggregate 7.19% in the Austin Prospect, 6.27% in the Nita Prospect and are neglible in other wells and prospects. These working interests bear their
share of lease operating costs and royalty burdens on the same basis as the Company. In addition, Bamaedge, L.P., a limited partnership of which Andex Energy Corporation is the general partner,
and Mr. Raphael also hold overriding royalty interests with respect to the Company's working interest in certain wells and prospects. Neither Mr. Raphael nor Bamaedge L.P. has an
overriding interest in excess of 0.075% in any one well or prospect. Essex I Joint Venture and Essex II Joint Venture (a joint venture of which Mr. Sfondrini and a company wholly owned by him
are the managers) own royalty and overriding royalty interests in various wells operated by the Company. The combined royalty and overriding royalty interests of the Essex I and Essex II Joint
Ventures do not exceed 6.2% in any one well or prospect. In September 2006, the Essex I and Essex II Joint Ventures sold all of their interests in wells operated by the Company except for one well in
which Essex II has a 1% gross working interest. Mr. Tugwell (an officer of the Company), Mr. Hastings (a former vice president of the Company) and Mr. Gabrisch (a former vice
president of the Company) own overriding royalty interests in various wells as a result of awards they received prior to 2000 when the Company had an overriding royalty program in effect for certain
key employees. The gross amounts paid or accrued to these persons and entities by the Company in 2007 (including net revenue, royalty and overriding royalty interests) and the amounts these same
persons and entities paid to the Company for their respective share of lease operating expenses and other costs is set forth in the following table:

|                                       |  | Total Amounts Paid by the Company to Owners Including Overriding Royalty(1)
|-------------------------------------- |  | ---------------------------------------------------------------------------
|
|
|Andex Corporation /Texedge Corporation |  | $                                                                          
|Bamaedge, L.P.                         |  |                                                                            
|Edge Group Partnership                 |  |                                                                            
|Edge Holding Co., L.P.                 |  |                                                                            
|Edge Limited Partnership               |  |                                                                            
|Edge Limited Partnership II            |  |                                                                            
|Edge Option I                          |  |                                                                            
|Edge Option II                         |  |                                                                            
|Edge Option III                        |  |                                                                            
|Essex I Royalty Joint Venture          |  |                                                                            
|Essex II Royalty Joint Venture         |  |                                                                            
|Mark J. Gabrisch(2)                    |  |                                                                            
|John O. Hastings(3)                    |  |                                                                            
|John O. Tugwell                        |  |                                                                            
|Stanley Raphael                        |  |                                                                            
|                                       |  |                                                                            
|Total                                  |  | $                                                                          
|                                       |  |                                                                            

---

F-45

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19.    RELATED PARTY TRANSACTIONS (Continued)

|                                       |  | Lease Operating Expenses Paid to the Company by Owners
|-------------------------------------- |  | ------------------------------------------------------
|
|
|Andex Corporation /Texedge Corporation |  | $                                                     
|Bamaedge, L.P.                         |  |                                                       
|Edge Group Partnership                 |  |                                                       
|Edge Holding Co., L.P.                 |  |                                                       
|Edge Limited Partnership I             |  |                                                       
|Edge Limited Partnership II            |  |                                                       
|Edge Option I                          |  |                                                       
|Edge Option II                         |  |                                                       
|Edge Option III                        |  |                                                       
|Essex II Royalty Joint Venture         |  |                                                       
|Stanley Raphael                        |  |                                                       
|                                       |  |                                                       
|Total                                  |  | $                                                     
|                                       |  |                                                       

20.    SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES

A summary of non-cash investing and financing activities for the years ended December 31, 2007, 2006 and 2005 is presented below:

Description

Number
of shares
issued

Fair
Market
Value(in thousands)2007:Shares issued to satisfy restricted stock grants

133

$
2,423Shares issued to fund the Company's matching contribution under the Company's 401(k) plan

37

$
5082006:Shares issued to satisfy restricted stock grants

119

$
1,803Shares issued to fund the Company's matching contribution under the Company's 401(k) plan

22

$
4292005:Shares issued to satisfy restricted stock grants

59

$
570Shares issued to fund the Company's matching contribution under the Company's 401(k) plan

10

$
168


F-46

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20.    SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES (Continued)

For the years ended December 31, 2007, 2006 and 2005, the non-cash portion of Asset Retirement Costs was $3.0 million,
$0.4 million, and $0.4 million, respectively. A supplemental disclosure of cash flow information for the years ended December 31, 2007, 2006 and 2005 is presented below:

For the Year Ended December 31,2007

2006

2005(in thousands)Cash paid during the period for:Interest, net of amounts capitalized

$
10,123

$
1,959

$
Current state income tax


5





Federal alternative minimum tax payments





94


327


21.    SUPPLEMENTAL FINANCIAL QUARTERLY RESULTS (unaudited):

The sum of the individual quarterly basic and diluted earnings (loss) per share amounts may not agree with year-to-date basic and diluted
earnings (loss) per share amounts as a result of each period's computation being based on the weighted average number of common shares outstanding during that period.

|         |                                   | Fourth
Quarter |   | Third
Quarter(2) |   | Second
Quarter |          | First
Quarter |  
|-------- | --------------------------------- | -------------- | - | ---------------- | - | -------------- | -------- | ------------- | -
|
|2007(1): |                                   |                |   |                  |   |                |          |               |  
|         | Oil and natural gas revenue       |                | $ | 35,931           |   | $              | 48,184   |               | $
|         | Operating expenses                |                |   | (39,884          | ) |                | (36,364  | )             |  
|         |                                   |                |   |                  |   |                |          |               |  
|         | Operating income (loss)           |                |   | (3,953           | ) |                | 11,820   |               |  
|         | Other expense, net                |                |   | (2,846           | ) |                | (2,334   | )             |  
|         | Income tax (expense) benefit      |                |   | 2,496            |   |                | (3,460   | )             |  
|         |                                   |                |   |                  |   |                |          |               |  
|         | Net income (loss)                 |                | $ | (4,303           | ) | $              | 6,026    |               | $
|         |                                   |                |   |                  |   |                |          |               |  
|         | Basic earnings (loss) per share   |                | $ | (0.22            | ) | $              | 0.14     |               | $
|         | Diluted earnings (loss) per share |                | $ | (0.22            | ) | $              | 0.14     |               | $
|2006:    |                                   |                |   |                  |   |                |          |               |  
|         | Oil and natural gas revenue       |                | $ | 24,931           |   | $              | 35,941   |               | $
|         | Operating expenses                |                |   | (19,364          | ) |                | (122,619 | )             |  
|         |                                   |                |   |                  |   |                |          |               |  
|         | Operating income (loss)           |                |   | 5,567            |   |                | (86,678  | )             |  
|         | Other expense, net                |                |   | (478             | ) |                | (809     | )             |  
|         | Income tax (expense) benefit      |                |   | (2,157           | ) |                | 30,607   |               |  
|         |                                   |                |   |                  |   |                |          |               |  
|         | Net income (loss)                 |                | $ | 2,932            |   | $              | (56,880  | )             | $
|         |                                   |                |   |                  |   |                |          |               |  
|         | Basic earnings (loss) per share   |                | $ | 0.17             |   | $              | (3.27    | )             | $
|         | Diluted earnings (loss) per share |                | $ | 0.16             |   | $              | (3.27    | )             | $

---

F-47

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

21.    SUPPLEMENTAL FINANCIAL QUARTERLY RESULTS (unaudited): (Continued)

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

This footnote provides unaudited information required by SFAS No. 69,Disclosures About Oil and Natural Gas Producing
Activities. The Company's oil and natural gas properties are located within the United States of America, which constitutes one cost center.

Capitalized CostsCapitalized costs and accumulated depletion relating to the Company's oil and
natural gas producing activities, all of which are conducted within the continental United States, are summarized below:

As of December 31,2007

2006(in thousands)Developed oil and natural gas properties(1)

$
1,059,788

$
521,713Unevaluated oil and natural gas properties


34,865


57,577Accumulated depletion


(381,689
)

(290,863
)Net capitalized cost

$
712,964

$
288,427




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

For the Year Ended December 31,2007

2006

2005(in thousands)Acquisition cost:Unproved properties

$
64,483

$
21,661

$
33,948Proved properties(1)


336,022


36,573


66,472Exploration costs


41,240


17,898


20,426Development costs(2)


74,920


65,140


59,121Total costs incurred

$
516,665

$
141,272

$
179,967




F-48

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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



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

Results of OperationsResults of operations for the Company's oil and natural gas producing activities
are summarized below:

For the Year Ended December 31,2007

2006

2005(in thousands)Oil and natural gas revenue

$
160,900

$
129,744

$
121,183Operating expenses:Oil and natural gas operating expenses and ad valorem taxes


21,774


11,836


10,102Production taxes


8,422


6,421


6,966Accretion expense


297


189


141Depletion expense


90,826


60,472


39,810Impairment of oil and natural gas properties





96,942


Income tax expense (benefit)


13,853


(16,141
)

22,457Results of operations from oil and gas producing activities

$
25,728

$
(29,975
)
$
41,707


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

The
Company's reserves increased significantly in 2007 primarily due to the January 2007 Acquisition. Increases in reserves from extensions and discoveries in 2007 were primarily the
result of the drilling of 46 productive wells, 87% development wells and 13% exploratory wells. Revisions of previous estimates during 2007 were primarily due to (1) the drilling of two PUD
locations that were dry holes, one in southeast Texas and one in south Texas (2) writing down 13 PUD locations' reserves primarily based on poor offset well performance, (3) poor
response on recompletions in south Texas that affected proved behind pipe reserves and (4) updated performance (both positive and negative) on existing wells. The Company's net ownership in
estimated quantities of proved oil and natural gas

F-49

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

reserves
and changes in net proved reserves, all of which are located in the continental United States, are summarized below.

|                                           |                   | Natural Gas
(MMcf) |         | Oil &
Condensate
(MBbls) |       | Natural Gas
Liquids
(MBbls) |       | Total
(MMcfe) |        
|------------------------------------------ | ----------------- | ------------------ | ------- | ------------------------ | ----- | --------------------------- | ----- | ------------- | -------
|Proved developed and undeveloped reserves  |                   |                    |         |                          |       |                             |       |               |        
|January 1, 2005                            |                   | 66,311             |         | 2,023                    |       | 1,769                       |       | 89,064        |        
|Revisions of previous estimates            |                   | (7,737             | )       | (257                     | )     | (383                        | )     | (11,577       | )      
|Purchase of oil and gas properties         |                   | 10,168             |         | 114                      |       |                            |       | 10,852        |        
|Extensions and discoveries                 |                   | 26,145             |         | 620                      |       | 155                         |       | 30,795        |        
|Production                                 |                   | (12,597            | )       | (324                     | )     | (307                        | )     | (16,384       | )      
|                                           |                   |                    |         |                          |       |                             |       |               |        
|                                           | December 31, 2005 |                    | 82,290  |                          | 2,176 |                             | 1,234 |               | 102,750
|                                           |                   |                    |         |                          |       |                             |       |               |        
|Proved developed reserves at year end 2005 |                   | 59,066             |         | 1,720                    |       | 1,132                       |       | 76,178        |        
|                                           |                   |                    |         |                          |       |                             |       |               |        
|January 1, 2006                            |                   | 82,290             |         | 2,176                    |       | 1,234                       |       | 102,750       |        
|Revisions of previous estimates            |                   | (13,526            | )       | (158                     | )     | 833                         |       | (9,476        | )      
|Purchase of oil and gas properties         |                   | 12,083             |         | 307                      |       | 15                          |       | 14,015        |        
|Extensions and discoveries                 |                   | 9,202              |         | 431                      |       | 71                          |       | 12,214        |        
|Sales of natural gas properties            |                   | (52                | )       | (12                      | )     | (5                          | )     | (154          | )      
|Production                                 |                   | (13,850            | )       | (345                     | )     | (222                        | )     | (17,251       | )      
|                                           |                   |                    |         |                          |       |                             |       |               |        
|                                           | December 31, 2006 |                    | 76,147  |                          | 2,399 |                             | 1,926 |               | 102,098
|                                           |                   |                    |         |                          |       |                             |       |               |        
|Proved developed reserves at year end 2006 |                   | 60,163             |         | 1,977                    |       | 1,181                       |       | 79,111        |        
|                                           |                   |                    |         |                          |       |                             |       |               |        
|January 1, 2007                            |                   | 76,147             |         | 2,399                    |       | 1,926                       |       | 102,098       |        
|Revisions of previous estimates            |                   | (65,450            | )       | (769                     | )     | (11                         | )     | (70,134       | )      
|Purchase of oil and gas properties         |                   | 98,491             |         | 1,468                    |       | 2,392                       |       | 121,651       |        
|Extensions and discoveries                 |                   | 26,306             |         | 468                      |       | 1,111                       |       | 35,780        |        
|Sales of natural gas properties            |                   | (1,397             | )       | (62                      | )     | (6                          | )     | (1,805        | )      
|Production                                 |                   | (17,536            | )       | (460                     | )     | (637                        | )     | (24,118       | )      
|                                           |                   |                    |         |                          |       |                             |       |               |        
|                                           | December 31, 2007 |                    | 116,561 |                          | 3,044 |                             | 4,775 |               | 163,472
|                                           |                   |                    |         |                          |       |                             |       |               |        
|Proved developed reserves at year end 2007 |                   | 88,134             |         | 2,580                    |       | 3,732                       |       | 126,005       |        
|                                           |                   |                    |         |                          |       |                             |       |               |        

F-50

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Standardized MeasureThe Standardized Measure of Discounted Future Net Cash Flows relating to the
Company's ownership interests in proved oil and natural gas reserves for each of the three years ended December 31, 2007 is shown below:

For the Year Ended December 31,2007

2006

2005(in thousands)Future cash inflows

$
1,314,304

$
616,605

$
949,752Future oil and natural gas operating expenses


(253,071
)

(131,926
)

(192,550
)Future development costs


(155,991
)

(75,389
)

(79,651
)Future income tax expense


(114,311
)

(65,738
)

(173,019
)Future net cash flows


790,931


343,552


504,53210% discount factor


(248,412
)

(110,346
)

(160,742
)Standardized measure of discounted future net cash flows

$
542,519

$
233,206

$
343,790


In
accordance with SEC regulations, the oil and natural gas prices in effect at December 31, 2007, adjusted for basis and quality differentials, are applied to
year-end quantities of proved oil and natural gas reserves to compute future cash flows. The base prices before adjustments were $6.80 per MMbtu of natural gas, $57.60 per Bbl of natural
gas liquids and $96.00 per Bbl of oil.

Future
oil and natural gas operating expenses and development costs are computed primarily by the Company's internal petroleum engineers and are provided to external independent
petroleum engineers as estimates of expenditures to be incurred in developing and producing the Company's proved oil and natural gas reserves at the end of the year, based on year-end
costs and assuming the continuation of existing economic conditions.

Future
income taxes are based on year-end statutory rates, adjusted for net operating loss carryforwards and tax credits. A discount factor of 10% was used to reflect the
timing of future net cash flows. The Standardized Measure of Discounted Future Net Cash Flows is not intended to represent the replacement cost or fair market value of the Company's oil and natural
gas properties.

The
Standardized Measure of Discounted Future Net Cash Flows does not purport, nor should it be interpreted, to present the fair value of the Company's oil and natural gas reserves. An
estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, a discount factor
more representative of the time value of money and the risks inherent in reserve estimates.

F-51

---



EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Changes in Standardized MeasureChanges in Standardized Measure of Discounted Future Net Cash Flows
relating to proved oil and gas reserves are summarized below:

For the Year Ended December 31,2007

2006

2005(in thousands)Changes due to current year operations:Sales of oil and natural gas, net of oil and natural gas operating expenses

$
(144,225
)
$
(101,520
)
$
(105,638
)Sales of oil and natural gas properties


(3,621
)

(618
)

Purchase of oil and gas properties


257,789


34,855


58,022Extensions and discoveries


120,691


42,085


119,850Changes due to revisions of standardized variables:Prices and operating expenses


577,668


(190,802
)

143,600Revisions of previous quantity estimates


(621,745
)

(29,018
)

(54,208
)Estimated future development costs


60,578


44,992


14,054Income taxes


(29,070
)

72,792


(74,281
)Accretion of discount


23,320


34,379


21,687Production rates (timing) and other


67,928


(17,729
)

3,833Net change


309,313


(110,584
)

126,919Beginning of year


233,206


343,790


216,871End of year

$
542,519

$
233,206

$
343,790


Sales
of oil and natural gas, net of oil and natural gas 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 due to revisions in standardized variables are reported on a pre-tax discounted basis, while the accretion of discount is
presented on an after-tax basis.

F-52

---





INDEX TO EXHIBITS

|Exhibit No. |  |  
|----------- |  | -
|2.1         |  | 
|2.2         |  | 
|2.3         |  | 
|2.4         |  | 
|2.5         |  | 
|2.6         |  | 
|3.1         |  | 
|3.2         |  | 
|3.3         |  | 
|3.4         |  | 

---



|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 (File No. 000-22149)
).                                                                                                                                                                                                                                                                                                                                        
|--- |  | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|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).                                                                                                                                                                                                                                                                                                                                                                        
|3.7 |  |  |  | Certificate of Designations establishing the 5.75% Series A cumulative convertible perpetual preferred stock, dated January 25, 2007 (Incorporated by reference to exhibit 3.1 to Edge's Current Report on Form 8-K filed
January 30, 2007).                                                                                                                                                                                                                                                                                                                               
|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).                                                                                                                                                                                                                 

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|10.1   |  |  |  | Form of Indemnification Agreement between the Company and each of its directors (Incorporated by reference from exhibit 10.7 to the Company's Registration Statement on Form S-4 (Registration No. 333-17269)).                                                                                                                         
|------- |  | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.2   |  |  |  | Stock Option Plan of Edge Petroleum Corporation, a Texas corporation (Incorporated by reference from exhibit 10.13 to the Company's Registration Statement on Form S-4 (Registration No. 333-17269)).                                                                                                                                   
|10.3   |  |  |  | Employment Agreement dated as of November 16, 1998, by and between the Company and John W. Elias (Incorporated by reference from exhibit 10.12 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998 (File
No. 000-22149)).                                                                                  
|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 (File No. 000-22149)). 
|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 (File No. 000-22149)).
|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 (File No. 000-22149)).                                                       
|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 (File No. 000-22149)).                                                            
|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 29, 2006).                                                                                                                                        

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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 16, 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 5, 2007). 
|*12.1  |  |  |  | Statement of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.                                                                                                                                                                          
|*21.1  |  |  |  | Subsidiaries of the Company.                                                                                                                                                                                                                                                    
|*23.1  |  |  |  | Consent of BDO Seidman, LLP.                                                                                                                                                                                                                                                    
|*23.2  |  |  |  | Consent of Ryder Scott Company.                                                                                                                                                                                                                                                 
|*23.3  |  |  |  | Consent of W.D. Von Gonten & Co.                                                                                                                                                                                                                                                
|*31.1  |  |  |  | Certification by John W. Elias, Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                             
|*31.2  |  |  |  | Certification by Michael G. Long, Chief Financial and Accounting Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                            
|*32.1  |  |  |  | Certification by John W. Elias, Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                             
|*32.2  |  |  |  | Certification by Michael G. Long, Chief Financial and Accounting Officer, 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, 2007.                                                                                                                                                                                   
|*99.2  |  |  |  | Summary of Reserve Report of W. D. Von Gonten & Co. Petroleum Engineers as of December 31, 2007.                                                                                                                                                                                

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