10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the 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	(I.R.S. Employer
incorporation or organization)	Identification No.)
1301 Travis, Suite 2000
Houston, Texas	77002
(Address of principal executive offices)	(Zip code)

713-654-8960

(Registrant’s telephone number, including area code)

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

None

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

Common Stock, Par Value $.01 Per Share

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.  o Yes 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.              o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filed, or a non-accelerated filer. See definition of “accelerated filer and larger accelerated filer” in Rule 12b-2 of the Exchange Act.:

o Large accelerated filer ýAccelerated Filer o Non-accelerated filer

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

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

As of March 10, 2006, 17,239,679 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 2006 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.

TABLE OF CONTENTS

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

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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 document (including the portion, if any, to which this Form 10-K is attached), 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), 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” 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 is www.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 at www.sec.gov that 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

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 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. Following a top-level management change in late 1998, a more disciplined style of business planning and management was integrated into our technology-driven drilling activities. We believe the continuation of this disciplined business model has resulted in continued growth in reserves, production and financial strength and flexibility.

Recent Developments & Accomplishments

At year-end 2005, our net proved reserves were 102.8 Bcfe, comprised of 82.3 billion cubic feet of natural gas, 1.2 million barrels of natural gas liquids and 2.2 million barrels of crude oil and condensate. Natural gas and natural gas liquids accounted for approximately 87% of those proved reserves. Approximately 74% of total proved reserves were developed as of year-end 2005 and they were all located onshore, in the United States. We spent much of 2005 (i) developing and exploiting assets acquired late in 2004, (ii) developing those assets in our southeast New Mexico exploration alliance entered into late in 2003, and (iii) developing our remaining core asset base. On February 14, 2005, we announced that we had entered into a new exploration and development venture to jointly explore for oil and natural gas in south Texas with a private oil and gas company. This venture is called the “Vista Nueva” project and it gives us access to 3-D seismic data covering a portion of our 2004 asset acquisition plus undeveloped acreage and an exclusive option to secure leases of unleased minerals in the Queen City project area. Operating successes in 2005 included:

•Growing reserves to a record high for the Company;

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

•Drilling 65 wells with an apparent success rate of 95%;

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

•Expansion of activity into the Floyd and Fayettville Shale plays.

Strategy

Our business strategy is based on the following six main elements:

1.Grow reserves through 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 2005, we drilled 65 wells (35.45 net), primarily in Texas, with 62 (33.20 net) of those wells completed as productive for an apparent success rate of approximately 95%. This drilling program, along with our acquisition of certain oil and gas assets on the Chapman Ranch Field, helped us to grow our year-end proved reserves by 15% and replaced 184% of our reserves (see “Oil and Natural Gas Reserve Replacement”). We expect our drilling program for 2006 to be focused primarily in south Texas, and to a lesser extent in southeastern New Mexico and Mississippi. We currently expect to drill between 55 and 60 wells (32 and 35 net, respectively) in 2006 and we estimate capital spending for drilling for the year to be approximately $98 million. In addition, we have a contingent drilling program that could add wells and costs to this estimate. Our contingent drilling program is dependent upon certain factors, including success of various related wells, commodity pricing, obtaining rigs and other services, obtaining certain leases and the availability of sufficient cash flow from operations to execute the program without materially increasing our debt.

2.Balance exploration risk with the exploitation of existing properties and acquisitions that we believe have upside potential. In 2005, 64% of our reserve growth came from our drilling activity (which includes additions, extensions

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and revisions from new drilling, well work and the addition of certain proved undeveloped locations) and the remaining 36% came from acquisitions. We seek acquisitions of producing properties that typically have exploration or exploitation upside potential. We primarily seek properties in our existing core areas, or as a means to establish new core areas. We spent considerable effort in 2005 on acquisitions, and in the fourth quarter we successfully closed two separate transactions related to the Chapman Ranch Field. We continue to work diligently to identify and evaluate acquisition opportunities with the goal of identifying those that we believe would fit our strategic plan and add shareholder value.

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

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. We believe this focus will allow us to manage a growing asset base and add value to additional properties while controlling incremental costs and staffing requirements.

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. As of December 31, 2005, we had rights to approximately 2,759 square miles of 3-D seismic data principally located in Texas, Louisiana and Mississippi.

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 total debt-to-capital ratio of less than 30%. At December 31, 2005, our debt-to-total capital ratio was 30.7%, resulting from the use of debt to finance our acquisition program in 2005. Our 2006 plans include a modest reduction of debt from excess cash flows from operating activities.

We try to fund most of our ongoing capital expenditures using cash flow from operations, reserving our debt capacity for potential investment opportunities that we believe can profitably add to our program. Part of a sound financial structure is constant attention to costs, both operating and overhead costs. Over the past several years, we have worked diligently to control our operating and overhead costs and instituted a formal, disciplined capital budgeting process. We strive to be creative with the use of partnerships and alliances so as to leverage capital resources and enhance our ability to meet our objectives.

6.Use equity ownership and performance based compensation programs to attract and retain a high-quality workforce. Following a management change 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 February 28, 2006, our directors and employees, including executive officers, owned or had options to acquire an aggregate of approximately 11% of our outstanding common stock.

Employees

As of March 10, 2006, we had 67 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.

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Offices

We lease executive and corporate office space located in Travis Tower in 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 pretax net cash flows related to such reserves as of December 31, 2005. We engaged Ryder Scott Company (“Ryder Scott”) and W. D. Von Gonten & Co. (“WDVG”) to estimate our net proved reserves, projected future production, estimated future net revenue attributable to our proved reserves, and the present value of such estimated future net revenue as of December 31, 2005. 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 twelve years and WDVG has independently reviewed the reserves we acquired from Contango late in 2004 for the past four years. In estimating the reserve quantities that are economically recoverable, Ryder Scott and WDVG used year-end oil and natural gas prices in effect at December 31, 2005 and estimated development and production costs that were in effect during December 2005 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, 2005, 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 before income taxes was prepared using constant prices as of the calculation date, discounted at 10% per annum on a pretax basis, and is not intended to represent the current market value of the estimated oil and natural gas reserves owned by us. For further information concerning the present value of future net revenue from these proved reserves, see Note 20 to our consolidated financial statements. See ITEM 1A. “RISK FACTORS.”  The oil and natural gas reserve data included in or incorporated by reference in this document are only estimates and may prove to be inaccurate.

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

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

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

(3)Includes natural gas liquids.

(4)Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, net of estimated future production and development costs, using year-end NYMEX oil and natural gas prices in effect at December 31, 2005, which were $10.05 per MMbtu of natural gas and $61.04 per Bbl of oil. Management believes that the presentation of the present value of future net cash flows attributable to estimated proved reserves, discounted at 10% per annum (the “PV-10 Value”), may be considered a non-GAAP financial measure as defined in Item 10(e) of Regulation S-K, therefore the Company has included this reconciliation of the measure to the most directly comparable GAAP financial measure (Standardized measure of discounted future net cash flows). Management believes that the presentation of PV-10 Value provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company may impact the amount of future income taxes to be paid, the use of the pre-tax measure provides greater comparability

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

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 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, 2005, 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, 2005. 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. In particular, natural gas prices at December 31, 2005 were at or near their record highs. While crude oil prices have remained approximately the same since year-end, natural gas prices have experienced significant volatility and since that time prices for natural gas have fallen substantially. As of March 1, 2006, the average price of natural gas that the Company receives for its production had fallen to approximately $6.50 per Mcf. 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 capacity 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. 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, purchases, 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 (see ITEM 1A. “RISK FACTORS”). The values for these reserve additions and production are derived directly from the proved reserves table in Note 20 to our consolidated financial statements. Accordingly, we do not use unproved reserve quantities. It should be noted that 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, it might be noted that the percentage of reserves that were developed was 74%, 75% and 78% for the years ended December 31, 2005, 2004 and 2003, respectively. Set forth below is our reserve replacement ratio for the years ended December 31, 2005, 2004 and 2003.

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

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

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

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

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

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

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

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, 2005.

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

Acreage Data

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

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

Leases covering approximately 4,215 gross (2,661 net), 12,443 gross (9,604 net) and 25,291 gross (19,647 net) undeveloped acres are scheduled to expire in 2006, 2007 and 2008, 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.

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

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

* This is an estimate of the expiration of our option to acquire leased acreage based on our current well and seismic 3-D acquisition schedule.

Core Areas of Operation

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

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, 2005.

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

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

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Texas

We currently own an interest in 83,539 gross (34,469 net) acres in south and south-central Texas. Our areas of focus in this region are predominantly in the Wilcox (Lobo), Queen City, Yegua, Vicksburg and Frio producing trends. As of December 31, 2005, we operated approximately 87 producing wells, which along with our 215 non-operated wells accounted for about 83% of our total net production. We drilled 47 wells during 2005 in Texas, 44 of which were an apparent success. The majority of our 2005 drilling activity took place in the Queen City, Gato Creek (Lobo), and Encinitas (Vicksburg) project areas. We drilled 23 apparently successful wells in the Queen City project area, eight at Gato Creek and seven at Encinitas. In 2006, we currently expect to drill 35 to 40 wells (22.4 to 25.6 net, respectively) in our core areas in Texas. The majority of these wells are planned in the Queen City project area, the Encinitas Field and the Chapman Ranch Field.

The Chapman Ranch Field acquisitions increased our Texas property base in 2005. These acquisitions added to our existing position, notably in the Deep Frio trend in Nueces County, Texas (see Note 6 to our consolidated financial statements).

Louisiana

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

Mississippi

We currently own an interest in 20,948 gross (9,493 net) acres in Mississippi in the Mississippi Salt Basin area and an additional 37,117 gross (30,594 net) undeveloped acres in the Floyd Shale play. We acquired reserves and production in the Mississippi Salt Basin in south central Mississippi as part of the 2003 merger with Miller Exploration Company (“Miller”). The primary producing horizons in the Mississippi Salt Basin around the Miller properties include the Hosston, Sligo, Rodessa and James Lime sections. As of December 31, 2005, we operated nine producing wells, accounting for approximately 90% of our total net production in Mississippi. In 2005 we established a position in the Floyd Shale play in east central Mississippi. In 2006, we plan to increase our leasehold position, acquire additional 3-D seismic and could drill one to two wells (0.8 to 1.3 net) in the Mississippi Salt Basin.

Michigan

We currently own an interest in 658 gross (658 net) acres in Michigan. We acquired acreage and one producing well in south 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. We have no plans for additional activity in Michigan in 2006 at this time.

New Mexico / West Texas – Permian Basin

We established a new core area in southeastern New Mexico through an alliance with two private companies in 2003. We currently own an interest in 95,541 gross (18,777 net) acres in this area that we earned through a drilling obligation that we fulfilled during 2004 and 2005. The objectives in this area are shallow oil in the Yeso, San Andres, Queen and Grayburg formations, and deep gas in the Atoka and Morrow formations. Additional objectives are the Strawn, Cisco, Wolfcamp and Devonian formations. In 2005, we participated in the drilling of 11 (4.2 net) shallow and seven (2.2 net) deep wells. All of the wells were apparent successes. We also acquired an additional 1,280 gross (321 net) acres from federal and state lease sales. During 2006, we anticipate drilling 14 to 16 wells (5.4 to 5.8 net) wells in New Mexico, and also anticipate adding to our acreage position in this area through lease sale acquisitions.

Arkansas

We currently own an interest in 5,420 gross (4,571 net) undeveloped acres in the Fayetteville Shale play in south central Arkansas. In 2006, we plan to acquire additional acreage in this area.

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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. See ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF 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 and to hedge a portion of our production at prices exceeding forecast. All such hedging transactions provide for financial rather than physical settlement. See ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – CRITICAL ACCOUNTING POLICIES AND ESTIMATES – DERIVATIVES 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) for a portion of our oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure to 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 also reduces our potential exposure to adverse price movements. Our price risk management arrangements, to the extent we enter into any, apply to only a portion of our production, provide only partial price protection against declines in oil and natural gas prices and limit our potential gains from future increases in prices. On an ongoing basis, our management reviews all of our price risk management transaction policies, including volumes, accounting treatment, types of instruments and counter parties. 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 reviews our price risk management policies and trades. 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).

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

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

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

							Fair Value of Outstanding Hedging and Derivative Contracts as of
				Price		Volumes	December 31,
Transaction Date	Transaction Type	Beginning	Ending	Per Unit		Per Day	2005			2004(4)
Natural Gas (1):
05/04	Natural Gas Collar	01/01/2005	03/31/2005	$	5.00-$10.39	10,000MMbtu	$	—		$	92,703
07/04	Natural Gas Collar	04/01/2005	06/30/2005	$	5.00-$7.53	10,000MMbtu	—			9,162
07/04	Natural Gas Collar	07/01/2005	09/30/2005	$	5.00-$7.67	10,000MMbtu	—			(41,210		)
10/04	Natural Gas Collar	01/01/2005	12/31/2005	$	6.00-$9.52	10,000MMbtu	—			1,860,375
08/05	Natural Gas Collar	01/01/2006	12/31/2006	$	7.00-$10.50	10,000MMbtu	(2,497,823		)	—
08/05	Natural Gas Collar	01/01/2006	12/31/2006	$	7.00-$16.10	10,000MMbtu	(137,077		)	—
Crude Oil (2):
03/04	Crude Oil Collar	04/01/2004	12/31/2004	$	30.00-$35.50	400Bbl	—			(96,240		)
05/04 (08/04)	Crude Oil Collar (3)	01/01/2005	12/31/2005	$	35.00-$40.00	200/290Bbl	—			(468,308		)
08/05	Crude Oil Collar	01/01/2006	12/31/2006	$	55.00-$80.00	400Bbl	155,865			—-
							$	(2,479,035	)	$	1,356,482

(1)Our current hedging activities for natural gas were entered into on a per MMbtu delivered price basis, using the Houston Ship Channel Index, with settlement for each calendar month occurring five business days following the expiration date.

(2)Hedge accounting is not applied to our collars on crude oil, which were entered into on a per barrel delivered price basis, using the West Texas Intermediate Index, with settlement for each calendar month occurring five business days following the expiration date. The change in fair value is reflected in total revenue.

(3)In August 2004, we replaced the contract that was entered into May 2004 with a new contract that changes the volume and pricing terms. The put option is on 200 Bbls/d and the call option is on 290 Bbls/d. This transaction was completed at no additional cost to us.

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

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Sales to Major Customers

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

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

* Zero or less than 1%

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

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

In the exploration, development and production business, production is normally sold to relatively few customers. 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, 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. (See ITEM 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 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

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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 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 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 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 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 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, whether or to what extent that trend will continue, or what the ultimate effect will be on our

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sales of gas, cannot be predicted. 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. 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. The second of these required reviews was commenced in July 2005, where the FERC has proposed to continue use of the indexing methodology for a further five year period. We are not able at this time to predict the effects of these regulations, 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 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,

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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.

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

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, 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:

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

•the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;

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

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

•our financial resources and results; and

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

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” and ITEMS 1 AND 2. “BUSINESS AND PROPERTIES – CORE AREAS OF OPERATION.”

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. See ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – RISK MANAGEMENT ACTIVITIES - DERIVATIVES AND HEDGING” and ITEMS 1 AND 2. “BUSINESS AND PROPERTIES — OIL AND NATURAL GAS RESERVES” and “–MARKETING.”

We have in the past and may in the future be required to write down the carrying value of our oil and natural gas properties when oil and natural gas prices are depressed or unusually volatile. 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 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.

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We have hedged and may continue to hedge a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas.

In order to reduce our exposure to short-term fluctuations in the price of oil and natural gas, we periodically enter into hedging arrangements. Our hedging arrangements apply to only a portion of our production and 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 addition, our hedging arrangements may limit the benefit to us of increases in the price of oil and natural gas. See ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – RISK MANAGEMENT ACTIVITIES - DERIVATIVES AND HEDGING” and ITEMS 1 AND 2. “BUSINESS AND PROPERTIES – MARKETING.”

We depend on successful exploration, development and acquisitions 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

•timing and amount of capital expenditures;

•expertise and financial resources;

•inclusion of other participants in drilling wells; and

•use of technology.

The loss of key personnel could adversely affect us.

We depend to a large extent on the services 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. See ITEM 4.

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

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 active 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. See ITEM 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. See ITEMS 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. Further expansion is anticipated in 2006 both through increased drilling efforts and possible acquisitions. Any future growth 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, 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

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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. See ITEMS 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 Statement of Financial Accounting Standards No. 69, Disclosures About Oil and Natural Gas Producing Activities to 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. See ITEMS 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, 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, sales of assets and the distributions of cash or properties and that prohibit the payment of dividends and the incurrence of liens. The revolving 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 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 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 bank credit facility. See ITEM 7. “MANAGEMENT’S

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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. 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.

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

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

Our reliance on third parties for gathering and distributing 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.

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Miller’s former use of Arthur Andersen LLP as its independent public accountants may limit your ability to seek potential recoveries from them related to their work.

Arthur Andersen LLP, independent public accountants, audited the consolidated balance sheet of Miller and its subsidiary as of December 31, 2001, and the related consolidated statements of operations, equity and cash flows for the year ending December 31, 2001. On June 15, 2002, Arthur Andersen was convicted on a federal obstruction of justice charge, which was overturned in 2005. On June 27, 2002, Miller dismissed Arthur Andersen and engaged Plante & Moran, PLLC. Arthur Andersen has ceased operations shortly after the conviction. As a result, any recovery any Edge stakeholder may have from Arthur Andersen related to the claims that such stakeholder may assert related to the financial statements audited by Arthur Andersen, misstatements or omissions, if any, in this Form 10-K, will be limited by the financial circumstances of Arthur Andersen.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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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.

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 hole or well. 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-in or farm-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 acres or gross 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.

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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.

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

NGL’s. Natural gas liquids measured in barrels.

NRI or Net 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 subject to abnormally high pressure as a result of certain types of subsurface formations.

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.

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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.

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 interest or WI. 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.

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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.

Texas Comptroller Audit - - During the second quarter of 2004, we received notice that our franchise tax returns for the State of Texas would be audited for the tax years 1999 through 2002. After reviewing documents submitted, the agent representing the Office of the Comptroller of the State of Texas proposed adjustments to the calculation that would result in an increased franchise tax liability. The agent maintained that transfers by the parent company to its subsidiaries that we classified as intercompany loans should instead be classified as equity investments in the subsidiary. The State of Texas originally proposed that the franchise tax liability of the subsidiaries would be increased by approximately $3.0 million for the four-year period under audit.

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

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

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

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

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

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. Elias has 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 65 years old.

Michael G. Long has 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 53 years old.

John O. Tugwell has 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 and prior to that 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 42 years old.

Significant Employees

Howard Creasey has served as the Vice President of Exploration for the Company since October 2005 and prior to that served as 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 Howard 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 50 years old.

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

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recently a Senior Landman, for Shell Oil Company. Mr. Gabrisch holds a B.S. in Petroleum Land Management from the University of Houston. Mr. Gabrisch is 45 years old.

Kirsten A. Hink has served as Vice President & Controller of the Company since October 1, 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 39 years old.

James D. Keisling has served as Vice President of Production for the Company since April 2004. From May 2000 to April 2004, he served as Chief Engineer for the Company. From August 1989 to April 2000, he served as Production Manager of Ocean Energy, Inc., serving as Southern Region Production Manager before his departure. Mr. Keisling holds a B.S. degree in Civil Engineering from New Mexico State University. Mr. Keisling is a registered professional engineer in the State of Texas. He is 58 years old.

C.W. MacLeod has 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. Mr. MacLeod is a registered professional geologist in the State of Wyoming. He is 55 years old.

Robert C. Thomas has served 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 52 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 10, 2006, we estimate there were approximately 237 beneficial holders of our Common Stock. Our Common Stock is listed on the NASDAQ National Market (“NASDAQ”) and traded under the symbol “EPEX”. As of March 10, 2006, we had 17,239,679 shares outstanding and our closing price on NASDAQ was $24.97 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 Prices
	High	Low
	($)	($)
Calendar 2005
First Quarter	18.24	13.40
Second Quarter	16.86	12.46
Third Quarter	27.94	15.47
Fourth Quarter	28.49	20.05
Calendar 2004
First Quarter	14.61	8.67
Second Quarter	17.04	12.50
Third Quarter	19.24	13.26
Fourth Quarter	17.49	13.43

We have never paid a dividend, cash or otherwise, and do not intend to in the foreseeable future. In addition, under our current credit facility, we are restricted from paying cash 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. See ITEMS 1A. “RISK FACTORS– We do not intend to pay dividends and our ability to pay dividends is restricted.”

There were no repurchases of securities during the fourth quarter of 2005.

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

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

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

(2)As discussed in Note 6 to our consolidated financial statements, we completed the merger with Miller in December 2003, which affects the comparability of our results in 2004, and subsequent periods, to prior periods.

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

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

(5)Deferred compensation expense includes the non-cash charge or credit related to FASB Interpretation No. (“FIN”) 44, “Accounting for Certain Transactions involving Stock Compensation.” In May 1999, certain of our outstanding options were re-priced, which triggered the FIN 44 requirement of variable accounting for modifications in the terms of those stock options (see Note 2 to our consolidated financial statements).Each period can be impacted by (i) re-priced options that are exercised and (ii) the change in the value of outstanding repriced options based on the price of our common stock at period-end. Volatility in our stock price can have a significant impact on this amount, which may affect the comparability of our results for the periods presented.

(6)As discussed in Note 11 to our consolidated financial statements, we completed a public offering of our common stock on December 21, 2004 and a significant property acquisition on December 29, 2004, therefore certain of our results in 2004 and subsequent periods are not directly comparable to periods prior to 2004.

(7)EBITDA is defined as net income (loss) before cumulative effect of accounting change, interest expense and amortization of deferred loan costs (net of interest income and amounts capitalized), income tax expense, depletion, depreciation and amortization and accretion expense. EBITDA is a financial measure commonly used in the oil and natural gas industry, but is not defined under accounting principles generally accepted in the United States of America (“GAAP”). EBITDA should not be considered in isolation or as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP or as a measure of a company’s profitability or liquidity. Because EBITDA excludes some, but not all, items that affect net income, this measure may vary among companies. The EBITDA data presented above may not be comparable to a similarly titled measure of other companies. Our management believes that EBITDA is a meaningful measure to investors and provides additional information about our ability to meet our future liquidity requirements for debt service, capital expenditures and working capital. In addition, management believes that EBITDA is a useful comparative measure of operating performance and liquidity. For example, debt levels, credit ratings and, therefore, the impact of interest expense on earnings vary significantly between companies. Similarly, the tax positions of individual companies can vary because of their differing abilities to take advantage of tax benefits, with the result that their effective tax rates and tax expense can vary considerably. Finally, companies differ in the age and method of acquisition of productive assets, and thus the relative costs of those assets, as well as in the depreciation or depletion (straight-line, accelerated, units of production) method, which can result in considerable variability in depletion, depreciation and amortization expense between companies. Thus, for comparison purposes, management believes that EBITDA can be useful as an objective and comparable measure of operating profitability and the contribution of operations to liquidity because it excludes these elements.

(8)Working Capital is defined as current assets less current liabilities.

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

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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 acquisition activities that allow us to continue generating revenue, income and cash flows.

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

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

•Approach to the Business – additional information regarding our approach and strategy.

•Acquisitions and Divestitures – information about significant changes in our business structure.

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

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

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

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

•Risk Management Activities – Derivatives & Hedging – supplementary information regarding our price-risk management activities involving commodity contracts that are accounted for at fair value.

•Tax Matters – supplementary discussion of income tax matters.

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

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 gas prices. Historically, oil and gas markets have been cyclical and volatile, which makes future price movements difficult to predict. While our revenues 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

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

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. Moreover, costs associated with operating within our industry are substantial. The recent high commodity price environment has also led to increased costs in our industry, which together with increased demand for rigs, equipment, supplies and services, have made it difficult at times for us to further our growth, and made 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 gas wells and related facilities. These regulations may become more demanding in the future.

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

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 gas properties to augment our growth and provide future drilling opportunities. We periodically hedge our exposure to volatile oil and gas prices on a portion of our production to reduce price risk. As of December 31, 2005, we have entered into hedge contracts covering approximately 48% and 37% of our anticipated 2006 natural gas and crude oil production, respectively, before any future acquisitions. In 2005, we had 51% and 33% of natural gas and crude oil production, respectively, hedged.

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. In recent years we have been able to expand our capital budget during the year as a result of our drilling successes and acquisition program. Our Board recently approved a 2006 capital budget of approximately $98 million. Based on current expectations for production volumes and commodity prices, we expect to fund those capital expenditures from internally generated cash from operating activities, as well as modestly reduce our debt levels. We do not typically include acquisitions in our budgeted capital expenditures, but expect to fund those with either borrowings under our credit facility, proceeds from offerings of common stock or other securities under our shelf registration statement or other sources.

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

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 and we expect acquisitions will continue to play a significant role in our future plans for growth. 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 not budgeted. Specific timing of acquisitions cannot be predicted. Although we consider a wide variety of acquisitions, a significant part of our growth strategy is expected to be focused toward producing property acquisitions, which we believe have exploitable potential. Because of our financial flexibility, we are positioned to take advantage of opportunities to acquire producing properties as they may arise. 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. We believe through hard work, technical ability and creative thinking, we will continue to grow through both acquisitions and drilling. 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.

On December 4, 2003, we completed our acquisition of Miller Exploration Company (“Miller”). Miller was an independent oil and gas exploration and production company with exploration efforts concentrated primarily in the Mississippi Salt Basin of central Mississippi. Under the terms of the merger agreement, each share of issued and outstanding common stock of Miller was converted into 1.22342 shares of Edge common stock. We issued approximately 2.6 million shares of Edge common stock to the shareholders of Miller in exchange for all of the outstanding common stock of Miller. The merger was treated as a tax-free reorganization and accounted for as a purchase business combination under generally accepted accounting principles. We operate the majority of the acquired properties. We acquired Miller for the development and exploitation projects in Miller’s core area, increased financial flexibility, and expansion of our core areas. During 2005, we added to the land and seismic position in Mississippi acquired in the Miller merger and expect to see an increase in operating activity on those properties in 2006.

On October 7, 2004, we executed an Asset Purchase Agreement to acquire oil and natural gas properties located in south Texas from Contango Oil & Gas Company (“Contango”). The final cash purchase price for the acquisition was $40.1 million, which was adjusted from the original price of $50.0 million for the results of operations between the July 1, 2004 effective date and the December 29, 2004 closing date pursuant to the closing adjustment provisions. We financed the acquisition with proceeds from a public offering of our common stock under our shelf registration (see Note 11 to our consolidated financial statements). The properties acquired consisted of 39 non-operated producing wells with working interests ranging from approximately 41% to 75% and net revenue interests ranging from 29% to 56%. These properties, located primarily in Jim Hogg County, Texas and producing primarily from the Queen City formation, are in a geographic area that has been one of our most active and successful areas of focus in recent years. In addition to estimated proved reserves, our technical team also identified a substantial number of additional drilling locations on undeveloped acreage for which we realized much of the exploitable potential in 2005. We view this area as a major growth area for the Company in 2006.

On September 21, 2005, we executed two separate and definitive agreements (the “CRF 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 south Texas and (ii) additional working interests in the same field owned by two other private companies for an aggregate cash purchase price of approximately $62.8 million (of which $35.8 million is attributable to the stock purchase and

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$27.0 million is 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 consist of eight non-operated producing wells, one well undergoing completion operations, and one well shut in for evaluation, as well as an ownership in approximately 1,300 net acres of developed and undeveloped leasehold as of the closing date of November 30, 2005.

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

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

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 2005, we had no divestitures. During 2004 and 2003, our divestitures consisted of the sales of oil and gas properties for net proceeds of $60,000 and $330,100, respectively. Our 2004 net proceeds from asset divestitures were primarily derived from the sale of certain oil and gas properties and equipment in Texas, Mississippi and Louisiana. Our 2003 net proceeds from asset divestitures were primarily derived from the sale of our interest in two affiliated entities, Essex I and II Joint Ventures, and certain oil and gas properties in Texas and Louisiana.

OUTLOOK

•We successfully completed several acquisitions during 2005. We expect to continue to spend considerable effort in 2006 on acquisitions, as we seek to further our growth.

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

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

•During 2005, we initiated activities via the purchase of undeveloped leasehold in the Fayetteville Shale in Arkansas and Floyd Shale in Mississippi and Alabama. Both of these projects are new focus areas.

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

•To help protect against the possibility of downward commodity price movements, we have entered into several hedges covering approximately 48% of our expected natural gas production and 37% of our expected crude oil production streams for 2006.

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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, access to capital, the acquisitions market and factors referred to in “FORWARD LOOKING INFORMATION.”

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:

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

•changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated results of operations or financial condition.

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.

“Ceiling” Test — The full-cost method of accounting for oil and gas properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full-cost ceiling calculation. The ceiling is the discounted present value of our estimated total proved reserves adjusted for taxes and the impact of hedges on pricing, using a 10% discount rate. To the extent that our capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense. Once incurred, this impairment of oil and gas properties is not reversible at a later date even if oil and gas prices increase. No such impairment was required in the years ended December 31, 2005, 2004, and 2003. This calculation of our proved reserves could significantly impact our ceiling limitation used in determining whether an impairment of our capitalized costs is necessary. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are generally held constant indefinitely. Therefore, the future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs, but rather are based on prices and costs in effect as of the end of the period. Oil and natural gas prices used in the reserve valuation at December 31, 2005 were $61.04 per barrel and $10.05 per MMbtu. Commodity prices have decreased significantly since December 31, 2005.

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%.

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“Ceiling” limitation test — The most likely factor to contribute to a ceiling test impairment is the price used to calculate the reserve limitation threshold. A significant reduction in the prices at a future measurement date could trigger a full-cost ceiling impairment. At December 31, 2005, we had a cushion (i.e., the excess of the ceiling over our capitalized costs) of $151.1 million. A 10% increase or decrease in prices used would have increased or decreased our cushion by approximately 29%. Our hedging program would serve to mitigate some of the impact of any price decline. Our hedges did not impact the ceiling test in the first, second or fourth quarter of 2005, but did reduce the ceiling in the third quarter by approximately $15.5 million. Our hedges would not have impacted the ceiling if the natural gas price was 10% lower as these prices were within the collars, but had we increased the natural gas price by 10% the natural gas price would have been less than our hedge floor and therefore resulted in a decrease in the ceiling of $1.9 million. Another likely factor to contribute to a ceiling test impairment is a revised estimate of reserve volume. A 10% increase or decrease in reserve volume would have increased or decreased our cushion by approximately 19%.

Nature of Critical Estimate Item: Unproved Property Impairment- We have elected to use the full-cost method to account for our oil and gas activities. Investments in unproved properties are not amortized until proved reserves associated with the prospects can be determined or until impairment occurs. Unproved properties are evaluated quarterly for impairment on a property-by-property basis. 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.

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

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

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 January 1, 2003, the costs associated with this activity were capitalized to the full-cost pool and charged to income through depletion. We adopted Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations effective January 1, 2003, as discussed in Note 2 to our Consolidated Financial Statements. 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 then 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

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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 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 move from their current lows, 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 the accounting for income taxes under 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 is 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.

Assumptions/Approach Used: Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices). We are not currently required to pay any federal income taxes because of the prior generation of NOL’s carryforwards.

Effect if different assumptions used: We have engaged an independent public accounting firm to assist us in applying the numerous and complicated tax law requirements. However, despite our attempt to make an accurate estimate, the ultimate utilization of our NOL carryforwards is highly dependent upon our actual production and the realization of taxable income in future periods. 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 carryforwards from our financial statements.

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) for a portion of our oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from commodity price fluctuations. While all of these transactions are 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 transactions are recorded on the balance sheet at fair value. See ITEMS 1 AND 2. “BUSINESS AND PROPERTIES – MARKETING.”

Hedge Contracts - We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used for hedging are expected to be highly effective in offsetting changes in cash flows of the hedged transactions. In the event it is determined that the use of a particular derivative may not be or has ceased to be effective in pursuing a hedging strategy, hedge accounting is discontinued prospectively. The ongoing measurement of effectiveness determines whether the change in fair value is deferred through other comprehensive income (“OCI”) on the balance sheet or recorded immediately in revenue on the

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

Derivative Contracts - For transactions not accounted for using cash flow hedge accounting, the change in the fair value of the derivative contract is reflected in revenue immediately, and not deferred through OCI, and there is no measurement of effectiveness.

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.

Effect if different assumptions used: At December 31, 2005, 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 instrument to increase or decrease by approximately $0.3 million.

RESULTS OF OPERATIONS

This section includes discussion of our 2005, 2004 and 2003 results of operations. We are an independent energy company engaged in the exploration, development, acquisition and production of oil and natural gas. 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 south Texas, Mississippi, Louisiana and southeastern New Mexico.

Revenue and Production

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

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

(1)Includes effect of hedging and derivative transactions.

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

Our revenue is sensitive to changes in prices received for our products. 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,

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while, the economy, weather and other factors outside of our control could impact demand. During the third quarter of 2005, two large hurricanes impacted the Gulf Coast area, causing significant damage to platforms in the Gulf and numerous onshore facilities related to our industry. As a result, both oil and natural gas prices increased. We were fortunate to only experience minor production deferrals as a result of these hurricanes. We completed two acquisitions in the fourth quarter of 2005, which did not have significant impact on revenues and production due to timing, but we expect them to be a source of growth in 2006.

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

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

(1) Excludes the effect of hedging and derivative transactions.

(2) Includes the effect of hedging and derivative transactions.

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

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

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

Revenue from the sale of oil and condensate, excluding derivative activity, increased 103% for the year ended December 31, 2005 over the same period in 2004 and 121% for the year ended December 31, 2004 as compared to the same period in 2003 due to increased realized prices and production. The average realized price for oil and condensate before the derivative losses for the year ended December 31, 2005 was $53.57 per barrel compared to $39.77 per barrel in the same period of 2004. These higher average prices for 2005 resulted in an increase in revenue of approximately $4.5 million (based on 2005 production). The average realized price for oil and condensate before the derivative losses for the year ended December 31, 2004 was $39.77 per barrel compared to $31.48 per barrel in the same period of 2003. These higher average prices for 2004 resulted in an increase in revenue of approximately $1.8 million (based on 2004 production). Production volumes for oil and condensate increased to 887 Bbls/d for the year ended December 31, 2005 from 586 Bbls/d for the same period in 2004 and 336 Bbls/d for the same period in 2003. The increase in 2005 as compared to 2004 was due primarily to successful drilling in southeast New Mexico and at our Queen City and Encinitas projects, as well as the acquisition of existing production in the Queen City trend on December 29, 2004, partially offset by declines at the Duson Horst and Brandon projects. The increase in 2005 oil and condensate production as compared to 2004 resulted in an increase in revenue of approximately $4.3 million (based on 2004 comparable period average prices). The increase in 2004 as compared to 2003 was due primarily to production from the properties acquired from Miller and in south Texas, as well as new wells drilled during 2004 at our Encinitas, Gato Creek and Southeast New Mexico properties. The increase in 2004 oil and condensate production as compared to 2003 resulted in an increase in revenue of approximately $2.9 million (based on 2003 comparable period average prices).

Losses on hedging and derivatives have declined significantly since 2003. This has been a function of the types of contracts and the strategy applied in our price risk-management activities. The volume and price contract terms vary from period to period and therefore interact differently with the market prices. 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. In 2003, the losses were attributable 100% to natural gas contracts as compared to 2004 and 2005 when we began hedging our oil production. The following table summarizes the various components of the total loss on hedging and derivatives for each of the three years ended December 31, 2005, 2004 and 2003 and the impact each component had on our realized prices:

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

Should crude oil or natural gas prices increase or decrease from the current levels, it could materially impact our revenues. 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 physical sales of these commodities are vulnerable to the volatility of the market price movements, therefore we typically enter into contracts covering a portion of anticipated production to ensure certain cash flows that allow us to plan our business activities.

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Costs and Operating Expenses

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

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

* Not meaningful

Oil and natural gas operating expenses increased 85% between 2003 and 2004 and 71% between 2005 and 2004, a 217% increase of 2005 over 2003. The increase from 2003 to 2005 has been driven almost equally by activity increases and cost increases. Activity levels were impacted by bringing online 40 apparently successful wells during 2004 and 62 apparently successful wells in 2005. The 2005 and 2004 results were impacted by the addition of the Miller and south Texas properties (acquisitions late in 2003) that accounted for 26% of the total costs in 2004 and 23% in 2005. The 2005 results had the added costs from the newly acquired Contango properties (late 2004), which account for 21% of total costs in 2005, representing 50% of the increase from 2004 to 2005 and 31% of the increase from 2003 to 2005. The acquisitions of the Chapman Ranch Field properties late in 2005 should also add to costs in 2006. Operating expenses averaged $0.52 per Mcfe, $0.41 per Mcfe and $0.33 per Mcfe for the years ended December 31, 2005, 2004 and 2003, respectively. The increasing cost structure resulted from added costs for compression, workovers and salt-water disposal as well as inflation in our industry during 2005. We are witnessing increasing costs due to increased demand for oil field products and services. The oil and natural gas industry tends to be cyclical in nature and the demand for goods and services of oil field companies, suppliers and others associated with the industry can put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do many or all associated costs. When commodity prices decline, associated costs do not necessarily decline at the same rate.

Severance and ad valorem taxes increased in both periods. Severance tax expense for 2005 was 76% higher than 2004 and 2004 was 97% higher than 2003. Severance taxes are levied directly on our revenue dollars, so the increase is consistent with the increases in revenue. The severance tax rate realized increased from 5.3% in 2003 to 6.0% in 2004 and then decreased to 5.7% in 2005. The rate realized changes as a result of the changing mix of our production locations. We had a significant portion of production in other states such as Louisiana in 2003 as compared to the increase in production in Texas in 2004, which imposes a tax rate of approximately 7.5% of the revenue dollar. In 2005, we had an increasing amount of production in New Mexico which added another location to the mix. Ad valorem costs increased 296% in 2005 as compared to 2004 but decreased 5% in comparing 2004 to 2003. Increased commodity prices in 2005 resulted in a higher valuation of reserves by taxing authorities resulting

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

Depletion, depreciation and amortization (“DD&A”) and accretion expense for the year ended December 31, 2005 increased 83% over the year ended December 31, 2004 and 62% for the year ended December 31, 2004 over the year ended December 31, 2003. Full cost depletion on our oil and natural gas properties totaled $39.8 million in 2005, $21.5 million in 2004 and $12.9 million in 2003. These increases were driven by production volume increases in 2004 and depletion rate increases in 2005. For the year ended December 31, 2005, higher oil and natural gas production compared to the prior year period resulted in an increase in depletion expense of $7.6 million. Depletion expense on a unit of production basis for the year ended December 31, 2005 was $2.43 per Mcfe, 37% higher than the 2004 rate of $1.78 per Mcfe. The higher depletion rate per Mcfe resulted in an increase in depletion expense of $10.7 million. The increase in the depletion rate was primarily due to a higher amortizable base in 2005 compared to the prior year without a corresponding increase in reserves. For the year ended December 31, 2004, higher oil and natural gas production compared to the prior year period resulted in an increase in depletion expense of $6.4 million. Depletion expense on a unit of production basis for the year ended December 31, 2004 was $1.78 per Mcfe, 12% higher than the 2003 rate of $1.59 per Mcfe. The higher depletion rate per Mcfe resulted in an increase in depletion expense of $2.2 million. The increase in the depletion rate was primarily due to a higher amortizable base in 2004 compared to the prior year without a corresponding increase in reserves. Depreciation of other assets decreased 25% from 2004 to 2005 and 41% from 2003 to 2004 due to accelerating depreciation on leasehold improvements and computer equipment in 2003 and 2004. When we moved to a new office building early in 2003, we fully depreciated certain assets that would no longer be in service in the new location. Many older assets became fully depreciated at that time and were not replaced in 2004 and 2005. Accretion expense on our ARO liability has increased 43% in 2005 and 49% in 2004 for the addition of new obligations associated with wells added each year, as well as the fact that accretion is calculated using the interest method of allocation, which calculates interest on the cumulative balance such that the interest increases with each subsequent period.

Total general and administrative (“G&A”) expenses for the year ended December 31, 2005 were $12.4 million, an increase of 32% compared to the 2004 total of $9.4 million and 74% compared to the 2003 total of $7.1 million. Total G&A costs include deferred compensation related to repriced options, deferred compensation related to restricted stock grants and other G&A costs.

Deferred compensation expense consists of costs reported in accordance with FIN 44and amortization related to restricted stock awards. FIN 44 requires variable accounting for stock options with terms modified after issuance (see Note 2 to our consolidated financial statements). Variable accounting provides 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 re-priced 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. We adjust deferred compensation expense upward or downward on a monthly basis based on the trading price at the end of each such period. We are required to report under this rule as a result of non-qualified stock options granted to employees and directors in prior years and re-priced in May of 1999, as well as certain newly issued options in conjunction with the re-pricing. A FIN 44 charge on our re-priced stock options was required in 2005, 2004 and 2003 as a result of our stock price exceeding the exercise price of those re-priced options. The average price at December 31, 2005, 2004 and 2003 that was used to calculate this expense was $24.65 per share, $14.66 per share and $10.60 per share, respectively. The increase in deferred compensation for restricted stock awards is related to the increase in employee headcount during 2004 and 2005.

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

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

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

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

Also included in other income (expense) for the year ended December 31, 2005 and 2004 was $152,723 and $142,135 representing amortization of deferred loan costs associated with our credit facility. There were no such costs in 2003.

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

We are subject to state and federal income taxes and although we are currently 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. Deferred income tax provisions of $18.1 million, $8.3 million and $ 2.7 million were recorded for the years ended December 31, 2005, 2004 and 2003, respectively. The majority of the increase year over year has been the growth in income before income taxes. Due to changes in amounts of permanent tax differences, including meals and entertainment and compensation expense, our effective tax rate also changes from time to time. The effective rate was 35.2% for the year ended December 31, 2005, as compared to 35.3% in 2004 and 36.7% in 2003. As of December 31, 2005, approximately $55.8 million of net operating loss carryforwards have been accumulated or acquired that will begin to expire in 2020. We were required to make an alternative minimum tax payment for 2005 of $327,400.

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

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

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 capital spending. 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 decline is estimated to be approximately 22% 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 and, therefore capital budgets. 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 gas prices, industry conditions, prices, availability of goods and services and the extent to which oil and gas properties are acquired.

Our primary cash requirements are for exploration, development and acquisition of oil and gas properties, 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 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 have historically used our credit facility to supplement any deficiencies between operating cash flow and capital expenditures. We typically have funded acquisitions from borrowings under our credit facility, cash flow from operations and sales of common stock.

Significant changes to working capital may affect our liquidity in the short term. The increase in accrued fees for professional services and royalties payable at December 31, 2005 accounts for most of the increase in accrued liabilities. Therefore, we expect our short-term cash outflows for the first quarter of 2006 to increase as these liabilities come due. There are also advance payments made to one of our operators included in our current assets. As the actual costs are realized, this balance will diminish. The increase in the derivative instrument liability is indicative of potential future cash settlements on our hedge positions, which are scheduled to settle in the coming months. The fair market value of our outstanding hedge and derivative contracts is reflected on the balance sheet as a liability for the positions with each of our two counterparties. This hedge and derivative financial instrument is a liability because the future strip commodity prices exceed the price caps on our contracts at the balance sheet date, such that if the contracts were to settle at the balance sheet date we would have significant losses. 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 hedges and derivatives require us to pay a cash settlement, we are receiving higher cash inflows on the sale of unhedged production at higher prices, providing us with funds which would adequately cover any derivative and hedge payments when they come due.

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

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

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

During 2004 and early 2005, we realized increased cash flows as a result of our public stock offerings and exercises of options and warrants to acquire shares of our common stock. Most significant were the net proceeds of $47.8 million that we received, before direct costs of $0.6 million, from our December 2004 offering of our common stock and the related exercise of the underwriter’s over-allotment option for 525,000 additional shares of our common stock, resulting in an additional $7.2 million of net proceeds to us in January 2005. At December 31, 2005, we had certain options outstanding and exercisable for shares of our common stock. We typically do not rely on proceeds from the exercise of warrants and stock options to sustain our business as the timing of their exercise is unpredictable.

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

Net Cash Provided By Operating Activities

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

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

Although fluctuations in commodity prices have been the primary reason for our short-term changes in cash flow from operating activities, increased production volumes significantly impacted us in 2005. 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. Less predictable than production declines from our proved reserves is the impact of constantly changing oil and natural gas prices on cash flows and, therefore capital budgets.

For these reasons, we only forecast, for internal use by management, an annual cash flow. We do analyze contingent well opportunities that may extend further than one year, but do not rely on them for sustaining our business. These annual forecasts are revised monthly and capital budgets are reviewed by management and adjusted as warranted by market conditions. Longer-term cash flow and capital spending projections are neither developed nor used by management to operate our business.

In the event such capital resources are not available to us, our drilling and other activities may be curtailed. See ITEMS 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 $167.3 million in investing activities during 2005. 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 includes $14.4 million in expenditures attributable to land holdings, capitalized G&A and interest and $2.5 million for increased seismic data and other geological and geophysical expenditures. In connection with the acquisition we completed in December 2004, we are now required to make drilling advances to the operator of those properties. Therefore a new item in 2005 is drilling advances related to our Queen City properties of $4.3 million. The

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remaining capital expenditures were associated with computer hardware, office furniture and equipment for the expansion into additional office space.

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

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

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

Net Cash Provided By Financing Activities

Cash flows provided by financing activities totaled $72.6 million for the year ended December 31, 2005. We had $81.0 million in borrowings and $16.0 million in repayments under our credit facility. We incurred loan costs of approximately $47,000 in amending our credit facility. In addition, we received $7.6 million in proceeds from the issuance of common stock related to options and warrants 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.

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

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

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Credit Facility

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

The Credit Facility matures December 31, 2007 and is secured by substantially all of the Company’s assets. Borrowings under the Credit Facility bear interest at a rate equal to prime plus 0.50% or LIBOR plus 2.25%. As of December 31, 2005, our interest rate was 7.5%. As of December 31, 2005, $85.0 million in borrowings were outstanding under the Credit Facility and as of March 10, 2006 $94.0 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 also prohibits dividends and certain distributions of cash or properties and certain liens. The Credit Facility also contains the following financial covenants, among others:

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

•The Working Capital ratio requires that the amount of our consolidated current assets less our consolidated current liabilities, as defined in the Credit Facility Agreement, be at least $1.0 million. For the purposes of calculating the Working Capital ratio, the total of current assets is adjusted for unused capacity under the Credit Facility Agreement, and derivative financial instruments and the total of current liabilities is adjusted for the current portion of indebtedness under the Credit Facility Agreement, derivative financial instruments and asset retirement obligations.

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

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

Shelf Registration Statement

During the second quarter 2005, we filed a registration statement with the SEC which registered offerings of up to $390 million of any combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities of the Company. 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. In connection with the filing of the 2005 registration statement, we deregistered the remaining shares then available for sale under our earlier $150 million shelf registration statement filed in 2004.

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

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million, before other acquisition costs, and fund the costs of the offering and other general corporate purposes. On January 5, 2005, the underwriters exercised their over-allotment option for an additional 525,000 shares of common stock, which generated net proceeds to us of $7.2 million. These funds were used to reduce our outstanding debt. Each of these sales was made under our shelf registration statement. At December 31, 2005, we had $390 million remaining for issuance under our 2005 shelf registration statement.

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, 2005 by payment due date:

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

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

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

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

Risk Management Activities – Derivatives and Hedging

Due to the volatility of oil and natural gas prices, we may enter into, from time to time, price-risk management transactions (e.g., swaps, collars and floors) for a portion of our oil and natural gas production 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 also reduces our potential exposure to adverse price movements. Our arrangements, to the extent we enter into any, apply to only a portion of our production, provide only partial price protection against declines in oil and natural gas prices and limit our potential gains from future increases in prices. We also use price-risk management transactions to protect forward pricing as a bidding strategy with respect to acquisition offers and execution. None of these instruments are used for trading purposes. On a quarterly basis, our management sets all of our price-risk management policies, 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.

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”. 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 special cash flow hedge accounting. Therefore, depending on the type of transaction and the circumstances, different accounting treatment may apply to the timing and location of the income statement impact, but all derivatives are recorded on the balance sheet at fair value. The following table provides additional information regarding our various derivative and hedging transactions that were recorded at fair value on the balance sheet as of December 31, 2005.

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

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

	Fair Value of Contracts at December 31, 2005
Source of Fair Value	Maturity less than 1 year			Maturity 1-3 years		Maturity 4-5 years		Maturity in excess of 5 years		Total fair value
Prices actively quoted:	$	—		$	—	$	—	$	—	$	—
Prices provided by other external sources:
Asset	—			—		—		—		—
Liability	(2,479,035		)	—		—		—		(2,479,035		)
Prices based on models and other valuation methods:	—			—		—		—		—
Total	$	(2,479,035	)	$	—	$	—	$	—	$	(2,479,035	)

Tax Matters

At December 31, 2005, we have cumulative net operating loss carryforwards (“NOLs”) for federal income tax purposes of approximately $55.8 million, including $17.8 million of NOLs acquired in the Miller merger that expire beginning 2020 through 2024. 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.

Recently Issued Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment. This statement requires companies to measure the cost of employee services in exchange for an award of equity instruments based on a grant-date fair value of the award (with limited exceptions), and that cost must generally be recognized over the vesting period. SFAS No. 123(R) amends the original SFAS No. 123 and 95 that had allowed companies to choose between expensing stock options or showing pro forma disclosure only. This statement eliminates the ability to account for share-based compensation transactions using APB Opinion No. 25. We currently account for our stock-based compensation plans under the principles prescribed by APB Opinion No. 25. Accordingly, no stock option compensation cost is reflected in net income, as all options granted under the plan had an exercise price equal to the market value of the underlying common stock on the date of grant. The adoption of SFAS No. 123(R) will impact our results of operations, but will have no impact on our overall financial position. In March 2005, the SEC issued SAB No. 107. Among other things, SAB No. 107 provides interpretive guidance related to the interaction between SFAS No. 123(R) and certain SEC rules and regulations, as well as provides the SEC staff’s views regarding the valuation of share-based payment arrangements for public companies. SFAS No. 123(R) was to become effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005, but on April 14, 2005, the SEC issued press release 2005-57, which amends the compliance date of SFAS No. 123(R) until fiscal years beginning after June 15, 2005. We anticipate adopting the provisions of SFAS No. 123(R) in the first quarter of 2006 using the modified prospective method for transition. Under this method we will recognize compensation expense for all stock-based awards granted or modified on or after July 1, 2005, as well as any previously granted awards that are not fully vested as of July 1, 2005. Compensation expense will be measured based on the fair value of the awards previously calculated in developing the pro forma disclosures in accordance with the provisions of SFAS No. 123. We expect the impact to be immaterial due to the fact that we have not issued options since April 2004 and there will only be a minimal number of unvested options as of our adoption date. SFAS No. 123(R) also

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requires the benefits of tax deductions in excess of recognized compensation cost be reflected as a financing cash flow, rather than as an operating cash flow as currently required.

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

In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143 (“FIN 47”). FIN 47 clarifies that the term, “conditional asset retirement obligation” as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the control of the entity. Even though uncertainty about the timing and/or method of settlement exists and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred generally upon acquisition, construction, or development or through the normal operation of the asset. SFAS No. 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005. Retrospective application for interim financial information is permitted but is not required. The adoption of FIN 47 is not expected to have a material effect on our consolidated financial position, results of operations or cash flows.

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

In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments, which improves financial reporting by eliminating the exemption from applying SFAS No. 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments and allows a preparer to elect fair value measurement at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement (new basis) event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated. Providing a fair value measurement election also results in more financial instruments being measured at what the FASB regards as the most relevant attribute for financial instruments, fair value. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We are currently evaluating the impact of this standard on our financial position, results of operations and cash flows.

ITEM 7A. QUALITATIVE AND QUANTITATIVE 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

53

on the year-end December 31, 2005 outstanding borrowings and our applicable interest rate of 7.5%, a 10% change in interest rate would result in an increase or decrease of interest expense of approximately $0.6 million on an annual basis.

In the normal course of business we enter into hedging transactions, including commodity price collars, swaps and floors to mitigate our exposure to commodity price movements, but not for trading or speculative purposes. During 2005, we put in place several natural gas and crude oil collars for a portion of our 2006 production to achieve a more predictable cash flow. Please refer to Note 9 to our consolidated financial statements. 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. The following is a list of hedge and derivative contracts outstanding at December 31, 2005:

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

(1)Our current hedging activities for natural gas were entered into on a per MMbtu delivered price basis, using the Houston Ship Channel Index, with settlement for each calendar month occurring five business days following the expiration date.

(2)Hedge accounting is not applied to our collars on crude oil, which were entered into on a per barrel delivered price basis, using the West Texas Intermediate Index, with settlement for each calendar month occurring five business days following the expiration date. The change in fair value is reflected in revenue.

At December 31, 2005, the fair value of the outstanding hedge and derivative contracts was a net liability of approximately $2.5 million (See ITEM 7. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – RISK MANAGEMENT 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 outstanding net asset position to increase or decrease by approximately $0.3 million.

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.

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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 10, 2006, expressed an unqualified opinion on our consolidated financial statements and its assessment of Management’s Annual Report on Internal Control over Financial Reporting is included herein under paragraph (e).

(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 effected 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 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, 2005. The Company’s management conducted its assessment in accordance with the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Management has concluded, that as of December 31, 2005, the internal control over financial reporting was effective as of December 31, 2005, excluding the acquisition of Cinco Energy Corporation (“Cinco”) (see discussion below under paragraph (c)).

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 management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2005, which is filed herewith.

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

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

The effect of this guidance from the SEC is that, although Management’s Annual Report on Internal Control over Financial Reporting generally must include controls at all consolidated entities, such report need not include controls at a recently acquired consolidated entity if it is not possible for an assessment of the controls at such entity to be performed in the period between the consummation date and the date of Management’s assessment and, among other things, reference is made to such exclusion in Management’s Annual Report on Internal Control over Financial Reporting.

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

55

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

(d) Changes in Internal Control Over Financial Reporting. Other than those discussed under paragraph (c), there have not been any changes in the Company’s internal control over financial reporting during the fiscal quarter ended December 31, 2005 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

(e) Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Edge Petroleum Corporation

Houston, Texas

We have audited management’s assessment, included in the accompanying Form 10-K, that Edge Petroleum Corporation maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Edge Petroleum Corporation’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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and 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.

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

In our opinion, management’s assessment that Edge Petroleum Corporation maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also in our opinion, Edge Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

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We have also 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, 2005 and 2004 and the related consolidated statements of income and comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005 and our report dated March 10, 2006 expressed an unqualified opinion thereon.

/S/ BDO SEIDMAN, LLP

BDO Seidman, LLP

Houston, TX

March 10, 2006

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information regarding directors and executive officers required under ITEM 10 will be contained within the definitive Proxy Statement for the Company’s 2006 Annual Meeting of Shareholders (the “Proxy Statement”) under the headings “Election of Directors,” “Standing Committees, Board Organization, Director Nominations and Meetings” 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, 2005. 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 at www.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 by ITEM 11 will be contained in the Proxy Statement under the headings “Executive Compensation,” “Summary Compensation Table,” “Option/SAR Grants,” “Option/SAR Exercises and 2004 Year-End Option/SAR Values,” “401(k) Employee Savings Plan,” “Employment Agreements and Change of Control Agreements,” “Compensation Committee Interlocks and Insider Participation,” “Performance Graph” and “Compensation Committee Report on Executive Compensation” and is incorporated herein by reference.

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

The information required by ITEM 12 will 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

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

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

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

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)	Financial Statements and Schedules:
	1.	Financial Statements: See Index to the Consolidated Financial Statements and Supplementary Information immediately following the signature page of this report.
	2.	Financial Statement Schedule: See Index to the Consolidated Financial Statements and Supplementary Information immediately following the signature page of this report.
(b)	Exhibits: The following documents are filed as exhibits to this report:
	2.1 —		Amended and Restated Combination Agreement by and among (i) Edge Group II Limited Partnership, (ii) Gulfedge Limited Partnership, (iii) Edge Group Partnership, (iv) Edge Petroleum Corporation, (v) Edge Mergeco, Inc. and (vi) the Company, dated as of January 13, 1997 (Incorporated by reference from exhibit 2.1 to the Company’s Registration Statement on Form S-4 (Registration No. 333-17269)).
	2.2 —		Agreement and Plan of Merger dated as of May 28, 2003 among Edge Petroleum Corporation, Edge Delaware Sub Inc. and Miller Exploration Company (Miller”) (Incorporated by reference from Annex A to the Joint Proxy Statement/Prospectus contained in the Company’s Registration Statement on Form S-4/A filed on October 31, 2003 (Registration No. 333-106484)).
	2.3 —		Asset Purchase Agreement by and among Contango STEP, L.P., Contango Oil & Gas Company, Edge Petroleum Exploration Company and Edge Petroleum Corporation, dated as of October 7, 2004 (Incorporated by reference from exhibit 2.1 to the Company’s Current Report on Form 8-K filed October 12, 2004).
	2.4 —		Purchase and Sale Agreement, dated as of September 21, 2005 among Pearl Energy Partners, Ltd., and Cibola Exploration Partners, L.P., as Sellers; and Edge Petroleum Exploration Company as Buyer and Edge Petroleum Corporation as Guarantor (Incorporated by reference from exhibit 2.1 to the Company’s Current Report on Form 8-K filed October 19, 2005).
	2.5 —		Stock Purchase Agreement by and among Jon L. Glass, Craig D. Pollard, Leigh T. Prieto, Yorktown Energy Partners V, L.P., Yorktown Energy Partners VI, L.P., Cinco Energy Corporation, and Edge Petroleum Exploration Company and Edge Petroleum Corporation, dated as of September 21, 2005 (Incorporated by reference from exhibit 2.5 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2005).
	2.6 —		Letter Agreement dated November 18, 2005 by and among Edge Petroleum Exploration Company, Cinco Energy Corporation and Sellers (Incorporated by reference from exhibit 2.02 to the Company’s Current Report on Form 8-K filed December 6, 2005). Pursuant to Item 601(b)(2) of Regulation S-K, the Company had omitted certain Schedules to the Letter Agreement (all of which are listed therein) from this Exhibit 2.6. It hereby agrees to furnish a supplemental copy of any such omitted item to the SEC on its request.
	3.1 —		Restated Certificate of Incorporation of the Company effective January 27, 1997 (Incorporated by reference from exhibit 3.1 to the Company’s Current Report on Form 8-K filed April 29, 2005).
	3.2 —		Certificate of Amendment to the Restated Certificate of Incorporation of the Company effective January 31, 1997 (Incorporated by reference from exhibit 3.2 to the Company’s Current Report on Form 8-K filed April 29, 2005).
	3.3 —		Certificate of Amendment to the Restated Certificate of Incorporation of the Company effective April 27, 2005 (Incorporated by reference from exhibit 3.3 to the Company’s Current Report on Form 8-K filed April 29, 2005).
	3.4 —		Bylaws of the Company (Incorporated by Reference from exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).

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3.5 —	First Amendment to Bylaws of the Company on September 28, 1999 (Incorporated by reference from exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).
3.6 —	Second Amendment to Bylaws of the Company on May 7, 2003 (Incorporated by reference from exhibit 3.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2003).
4.1 —	Third Amended and Restated Credit Agreement dated December 31, 2003 among Edge Petroleum Corporation, Edge Petroleum Exploration Company, Edge Petroleum Operating Company, Inc., Miller Oil Corporation, and Miller Exploration Company, as borrowers, the lenders thereto and Union Bank of California, N.A., a national banking association, as Agent (Incorporated by reference from Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).
4.2 —	Agreement and Amendment No. 1 to Third Amended and Restated Credit Agreement dated May 31, 2005 among Edge Petroleum Corporation, Edge Petroleum Exploration Company, Edge Petroleum Operating Company, Inc., Miller Exploration Company and Miller Oil Corporation, as borrowers, the lenders thereto and Union Bank of California, N.A., a national banking association, as agent for the lenders (Incorporated by reference from Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2005).
*4.3 —	Agreement and Amendment No. 2 to the Third Amended and Restated Credit Agreement dated November 30, 2005 among Edge Petroleum Corporation, Edge Petroleum Exploration Company, Edge Petroleum Operating Company, Inc., Miller Oil Corporation, Miller Exploration Company, and Cinco Energy Corporation, as borrowers, the lenders thereto and Union Bank of California, N.A., a national banking association, as Agent.
4.4 —	Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference from exhibit 10.1(a) to Miller Exploration Company’s Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 000-23431)).
4.5 —	Amendment No. 1 to the Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference to Exhibit 4.2 from Miller Exploration Company’s Registration Statement on Form S-8 filed on April 11, 2001 (Registration No. 333-58678)).
4.6 —	Amendment No. 2 to the Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference from Exhibit 4.3 to Miller Exploration Company’s Registration Statement on Form S-8 filed on April 11, 2001 (Registration No. 333-58678)).
4.7 —	Form of Miller Stock Option Agreement (Incorporated by reference from exhibit 10.1(b) to Miller Exploration Company’s Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 000-23431)).
†10.1—	Form of Indemnification Agreement between the Company and each of its directors (Incorporated by reference from exhibit 10.7 to the Company’s Registration Statement on Form S-4 (Registration No. 333-17269)).
†10.2—	Stock Option Plan of Edge Petroleum Corporation, a Texas corporation (Incorporated by reference from exhibit 10.13 to the Company’s Registration Statement on Form S-4 (Registration No. 333-17269)).
†10.3—	Employment Agreement dated as of November 16, 1998, by and between the Company and John W. Elias (Incorporated by reference from 10.12 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998).

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†10.4—	Incentive Plan of Edge Petroleum Corporation as Amended and Restated Effective as of June 1, 2004 (Incorporated by reference from exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004).
†10.5—	Edge Petroleum Corporation Incentive Plan “Standard Non-Qualified Stock Option Agreement” by and between Edge Petroleum Corporation and the Officers named therein (Incorporated by reference from exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).
†10.6—	Edge Petroleum Corporation Incentive Plan “Director Non-Qualified Stock Option Agreement” by and between Edge Petroleum Corporation and the Directors named therein (Incorporated by reference from exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).
†10.7—	Severance Agreements by and between Edge Petroleum Corporation and the Officers of the Company named therein (Incorporated by reference from exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).
†10.8—	Form of Director’s Restricted Stock Award Agreement under the Incentive Plan of Edge Petroleum Corporation (Incorporated by reference from exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004).
†10.9—	Form of Employee Restricted Stock Award Agreement under the Incentive Plan of Edge Petroleum Corporation (Incorporated by reference from exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q/A for the quarterly period ended March 31, 1999).
†10.10—	Edge Petroleum Corporation Amended and Restated Elias Stock Incentive Plan. (Incorporated by reference from exhibit 4.5 to the Company’s Registration Statement on Form S-8 filed May 30, 2001 (Registration No. 333-61890)).
†10.11—	Form of Edge Petroleum Corporation John W. Elias Non-Qualified Stock Option Agreement (Incorporated by reference from exhibit 4.6 to the Company’s Registration Statement on Form S-8 filed May 30, 2001 (Registration No. 333-61890)).
*†10.12–	Summary of Compensation of Non-Employee Directors.
*†10.13–	Salaries and Other Compensation of Executive Officers.
*†10.14–	Description of 2005 Bonus Program for Executive Officers.
*21.1—	Subsidiaries of the Company.
*23.1—	Consent of BDO Seidman, LLP.
*23.2—	Consent of Ryder Scott Company.
*23.3—	Consent of W. D. Von Gonten & Co.
*31.1—	Certification by John W. Elias, Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2—	Certification by Michael G. Long, Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1—	Certification by John W. Elias, Chief Executive Officer, pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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*32.2—	Certification by Michael G. Long, Chief Financial Officer, pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*99.1—	Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 2005.
*99.2—	Summary of Reserve Report of W. D. Von Gonten & Co. Petroleum Engineers as of December 31, 2005.

* Filed herewith.

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

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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	/S/ John W. Elias
	John W. Elias
	Chief Executive Officer and Chairman of the Board
	Date: March 14, 2006

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

63

EDGE PETROLEUM CORPORATION

Index to Consolidated Financial Statements and Supplementary Information

CONSOLIDATED FINANCIAL STATEMENTS

Audited Financial Statements:

Unaudited Information:

Supplementary Information to Consolidated Financial Statements

CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

All schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and therefore have been omitted.

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, 2005 and 2004 and the related consolidated statements of income and comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. 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.

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, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, 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), the effectiveness of Edge Petroleum Corporation’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 10, 2006 expressed an unqualified opinion thereon.

/S/BDO Seidman, LLP

BDO Seidman, LLP

Houston, Texas

March 10, 2006

F-2

EDGE PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31,
	2005			2004
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	666,332		$	2,267,423
Accounts receivable, trade, net of allowance of $525,248 as of December 31, 2005 and 2004	24,980,196			12,756,097
Accounts receivable, joint interest owners and other, net of allowance of $4,771 and $82,000 as of December 31, 2005 and 2004	2,100,305			5,911,073
Deferred income taxes	2,517,659			660,223
Derivative financial instruments	—			1,824,790
Other current assets	6,436,693			1,445,923
Total current assets	36,701,185			24,865,529
PROPERTY AND EQUIPMENT, Net – full cost method of accounting for oil and natural gas properties (including unevaluated costs of $36.9 million and $15.5 million at December 31, 2005 and 2004, respectively)	306,455,515			165,840,345
OTHER ASSETS	223,175			284,280
TOTAL ASSETS	$	343,379,875		$	190,990,154
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable, trade	$	5,570,625		$	3,141,235
Accrued liabilities	17,894,439			12,105,694
Derivative financial instruments	2,479,035			468,308
Accrued interest payable	17,466			—
Asset retirement obligation – current portion	202,469			193,647
Total current liabilities	26,164,034			15,908,884
ASSET RETIREMENT OBLIGATION – long-term portion	2,563,777			1,995,441
DEFERRED TAX LIABILITY	37,896,759			2,618,934
LONG-TERM DEBT	85,000,000			20,000,000
Total liabilities	151,624,570			40,523,259
COMMITMENTS AND CONTINGENCIES (Note 12)
STOCKHOLDERS’ EQUITY
Preferred stock, $0.01 par value; 5,000,000 shares authorized; none issued and outstanding	—			—
Common stock, $0.01 par value; 60,000,000 shares authorized; 17,216,776 and 16,535,901 shares issued and outstanding at December 31, 2005 and 2004, respectively	172,168			165,359
Additional paid-in capital	137,841,756			126,957,059
Retained earnings	55,454,066			22,095,807
Accumulated other comprehensive income (loss)	(1,712,685		)	1,248,670
Total stockholders’ equity	191,755,305			150,466,895
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	343,379,875		$	190,990,154

See accompanying notes to the consolidated financial statements.

F-3

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

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

See accompanying notes to the consolidated financial statements.

F-4

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

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

See accompanying notes to the consolidated financial statements.

F-5

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

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

See accompanying notes to the consolidated financial statements.

F-6

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

	Common Stock			Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
	Shares	Amount
BALANCE,DECEMBER 31, 2002	9,416,254	$	94,163	$	56,663,626	$	2,616,507	$	(840,996	)	$	58,533,300
Issuance of common stock	3,164,778	31,647		16,889,740		—		—			16,921,387
Deferred compensation expense – restricted stock	—	—		372,151		—		—			372,151
Deferred compensation expense – repriced options	—	—		1,219,349		—		—			1,219,349
Tax benefit associated with exercise of non-qualified stock options	—	—		137,141		—		—			137,141
Reclassification of hedging losses	—	—		—		—		2,896,134			2,896,134
Change in valuation of hedging instruments	—	—		—		—		(2,418,612		)	(2,418,612		)
Net income	—	—		—		4,350,050		—			4,350,050
BALANCE,DECEMBER 31, 2003	12,581,032	125,810		75,282,007		6,966,557		(363,474		)	82,010,900
Issuance of common stock	3,954,869	39,549		49,579,032		—		—			49,618,581
Deferred compensation expense – restricted stock	—	—		498,372		—		—			498,372
Deferred compensation expense – repriced options	—	—		1,135,628		—		—			1,135,628
Tax benefit associated with exercise of non-qualified stock options	—	—		462,020		—		—			462,020
Reclassification of hedging losses	—	—		—		—		659,588			659,588
Change in valuation of hedging instruments	—	—		—		—		952,556			952,556
Net income	—	—		—		15,129,250		—			15,129,250
BALANCE,DECEMBER 31, 2004	16,535,901	165,359		126,957,059		22,095,807		1,248,670			150,466,895
Issuance of common stock	680,875	6,809		7,775,744		—		—			7,782,553
Deferred compensation expense – restricted stock	—	—		973,796		—		—			973,796
Deferred compensation expense – repriced options	—	—		1,627,814		—		—			1,627,814
Tax benefit associated with exercise of non-qualified stock options	—	—		507,343		—		—			507,343
Reclassification of hedging gains	—	—		—		—		799,435			799,435
Change in valuation of hedging instruments	—	—		—		—		(3,760,790		)	(3,760,790		)
Net income	—	—		—		33,358,259		—			33,358,259
BALANCE,DECEMBER 31, 2005	17,216,776	$	172,168	$	137,841,756	$	55,454,066	$	(1,712,685	)	$	191,755,305

See accompanying notes to the consolidated financial statements.

F-7

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 4,701,361 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 2,760,000 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).

Nature of Operations -The Company is an independent energy company engaged in the exploration, development, acquisition and production of oil and natural gas. 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 its primary emphasis in south Texas, Mississippi, Arkansas, Louisiana and Southeast New Mexico. 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 – None.

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 hedges. 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, 2005 and 2004 approximates fair value because the interest rates are variable and reflective of market rates. Our hedging 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.

Allowance for Doubtful Accounts - The Company routinely assesses the recoverability of all material trade and other receivables to determine our 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-8

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 three to seven years.

Oil and Natural Gas Properties - Investments in oil and natural gas properties are accounted for using the full cost method of accounting. The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry and 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. In the measurement of impairment of oil and gas properties, the successful-efforts method of accounting follows the guidance provided in Statement of Financial Accounting Standards (“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 comparing the net book value (full-cost pool) to the future net cash flows discounted at 10% using commodity prices in effect at the end of the reporting period.

In accordance with 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 $2.6 million, $2.2 million, and $1.7 million of general and administrative costs in 2005, 2004 and 2003, respectively. The Company also capitalizes a portion of interest expense on borrowed funds related to unproved oil and gas properties. The Company capitalized approximately $1.9 million, $0.7 million, and $0.2 million of interest costs in 2005, 2004 and 2003, respectively.

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 $36.9 million and $15.5 million at December 31, 2005 and 2004, 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 Securities and Exchange Commission (“SEC”) issued SEC Staff Accounting Bulletin (“SAB”) No. 106, Interaction of Statement 143 and the Full Cost Rules, which the Company adopted in the fourth quarter of 2004 with no impact on 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, 2005, 2004 and 2003 were $2.43, $1.78, and $1.59, respectively.

In addition, the capitalized costs of oil and natural gas properties are subject to a “ceiling test,” whereby to the extent that such capitalized costs subject to amortization in the full cost pool (net of depletion, depreciation and amortization, asset retirement obligations 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, such excess costs are charged to operations. Once incurred, an impairment of oil and natural gas properties is not reversible at a later date. In accordance with SAB No. 103, Update of Codification of Staff Accounting Bulletins, derivative instruments

F-9

qualifying as cash flow hedges are included in the computation of limitation on capitalized costs. The period-end price was between the cap and floor established by the Company’s hedge contracts at December 31, 2005 and thus no impact was included in the calculation. Impairment of oil and natural gas properties is assessed on a quarterly basis in conjunction with the Company’s quarterly filings with the SEC. The period-end price was within the collar established by the Company’s hedges at December 31, 2005 and thus did not affect prices used in this calculation. No adjustment related to the ceiling test was required during the years ended December 31, 2005, 2004, or 2003.

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. The Company adopted this policy effective January 1, 2003, using a cumulative effect approach to recognize transition amounts for asset retirement obligations, asset retirement costs and accumulated accretion and depletion. The cumulative effect of the adoption of SFAS No. 143 and the change in accounting principle was a charge to net income during the first quarter of 2003 of $357,825, net of taxes of $192,675 (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. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences, using currently enacted tax laws, attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases (see Note 14).

Stock-Based Compensation - The Company accounts for stock compensation plans under the intrinsic value method of Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees. No compensation expense is recognized for stock options that had an exercise price equal to the market value of the underlying common stock on the date of grant. As allowed by SFAS No. 123, Accounting for Stock Based Compensation, the Company has continued to apply APB Opinion No. 25 for purposes of determining net income, but SFAS No. 123, as amended, requires prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based compensation and the effect of the method used on reported results. SFAS No. 123 was revised in December 2004 to eliminate the use of APB Opinion No. 25 in 2006 (see Recently Issued Accounting Pronouncements below).

F-10

Had compensation expense for stock-based compensation been determined based on the fair value at the date of grant, our net income and earnings per share would have been as follows:

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

No options were granted in 2005. The weighted-average fair value of each option granted during 2004 and 2003 was $11.03 and $3.24, respectively. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions: expected stock price volatility of 72% and 73% in 2004 and 2003, respectively; risk free interest rate of 3.76% and 3.76% in 2004 and 2003, respectively; average expected option lives of ten years for 2004 and eight years in 2003, respectively; and over the vesting period of such options a forfeiture rate of 0% for 2004 and 10% for 2003.

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

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

Derivatives and Hedging Activities -The Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities effective January 1, 2001. The statement, as amended by SFAS No. 137 Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133 - an Amendment of FASB Statement No. 133 and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities - an Amendment of FASB Statement No. 133, 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 special hedge accounting treatment. If

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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”). The 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 (see Note 9). Upon adoption of SFAS No. 133, the Company recorded a transition adjustment of approximately $(1.1) million in accumulated other comprehensive income to record the fair value of the natural gas hedges that were outstanding at that date. If 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 other comprehensive income will be recognized in earnings immediately.

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 years ended December 31, 2005, 2004 and 2003, the only component of other comprehensive income has been changes in fair value of hedging instruments and reclassifications of hedging gains and losses.

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 $525,248 related to non-payments from two purchasers of the Company’s oil and natural gas, which is still in the allowance for doubtful accounts receivable until such time as the Company discontinues pursuing recovery efforts. 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. No bad debt expense was recorded in 2004 or 2003. The Company cannot ensure that similar such losses may not be realized in the future.

Recently Issued Accounting Pronouncements – In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment. This statement requires companies to measure the cost of employee services in exchange for an award of equity instruments based on a grant-date fair value of the award (with limited exceptions), and that cost must generally be recognized over the vesting period. SFAS No. 123(R) amends the original SFAS No. 123 and 95 that had allowed companies to choose between expensing stock options or showing pro forma disclosure only. This statement eliminates the ability to account for share-based compensation transactions using APB Opinion No. 25. The Company currently accounts for stock-based compensation plans under the principles prescribed by APB Opinion No. 25. Accordingly, no stock option compensation cost is reflected in net income, as all options granted under the plan had an exercise price equal to the market value of the underlying common stock on the date of grant.

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The adoption of SFAS No. 123(R) will impact results of operations, but will have no impact on overall financial position. In March 2005, the SEC issued SAB No. 107. Among other things, SAB No. 107 provides interpretive guidance related to the interaction between SFAS No. 123(R) and certain SEC rules and regulations, as well as provides the SEC staff’s views regarding the valuation of share-based payment arrangements for public companies. SFAS No. 123(R) was to become effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005, but on April 14, 2005, the SEC issued press release 2005-57, which amends the compliance date of SFAS No. 123(R) until fiscal years beginning after June 15, 2005. The Company anticipates adopting the provisions of SFAS No. 123(R) in the first quarter of 2006 using the modified prospective method for transition. Under this method the Company will recognize compensation expense for all stock-based awards granted or modified on or after July 1, 2005, as well as any previously granted awards that are not fully vested as of July 1, 2005. Compensation expense will be measured based on the fair value of the awards previously calculated in developing the pro forma disclosures in accordance with the provisions of SFAS No. 123. The Company expects the impact to be immaterial due to the fact that it has not issued options since April 2004 and there will only be a minimal amount of unvested options as of our adoption date. SFAS No. 123(R) also requires the benefits of tax deductions in excess of recognized compensation cost be reflected as a financing cash flow, rather than as an operating cash flow as currently required.

In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29. SFAS No. 153 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. APB Opinion No. 29, Accounting for Nonmonetary Transactions, provided an exception to its basic measurement principle (fair value) for exchanges of similar productive assets. Under APB Opinion No. 29, an exchange of a productive asset for a similar productive asset was based on the recorded amount of the asset relinquished. SFAS No. 153 eliminates the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. Nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS No. 153 is effective for fiscal periods beginning after June 15, 2005. The adoption of SFAS No. 153 is not expected to have a material effect on the Company’s consolidated financial position, results of operations or cash flows.

In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143 (“FIN 47”).  FIN 47 clarifies that the term, “conditional asset retirement obligation” as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the control of the entity.  Even though uncertainty about the timing and/or method of settlement exists and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional.  Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated.  Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists.  The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred generally upon acquisition, construction, or development or through the normal operation of the asset.  SFAS No. 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation.  FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.  FIN 47 is effective for fiscal years ending after December 15, 2005.  Retrospective application for interim financial information is permitted but is not required.  The adoption of FIN 47 is not expected to have a material effect on the Company’s consolidated financial position, results of operations or cash flows.

In June 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, a replacement of Accounting Principles Board (“APB”) Opinion No. 20 and FASB Statement No. 3, which changes the requirements for the accounting for and reporting of a change in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. Application is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The adoption of SFAS No. 154 is not expected to have a material effect on the Company’s consolidated financial position, results of operations or cash flows.

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In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments, which improves financial reporting by eliminating the exemption from applying SFAS No. 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments and allows a preparer to elect fair value measurement at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement (new basis) event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated. Providing a fair value measurement election also results in more financial instruments being measured at what the FASB regards as the most relevant attribute for financial instruments, fair value. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The Company is currently evaluating the impact of this standard on its financial position, results of operations and cash flows.

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

3.ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

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

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

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

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

(3)Other receivables represent various miscellaneous refunds or credits that the Company is due that may not relate to Joint Interest Billings or Trade Receivables.

The following table sets forth changes in the Company’s allowance for doubtful accounts for the years ended December 31, 2005, 2004 and 2003:

	Balance at Beginning of Year		Charged to Costs and Expenses		Deductions and Other			Balance at End of Year
Year ended December 31, 2005:
Allowance for doubtful accounts	$	607,248	$	65,157	$	(142,386	)	$	530,019
Year ended December 31, 2004:
Allowance for doubtful accounts	$	607,248	$	—	$	—		$	607,248
Year ended December 31, 2003:
Allowance for doubtful accounts	$	607,248	$	—	$	—		$	607,248

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4.OTHER CURRENT ASSETS

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

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

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

5.PROPERTY AND EQUIPMENT

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

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

The following table summarizes the cost of the properties not subject to amortization by the year the cost was incurred:

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

6.ACQUISITIONS AND DIVESTITURES

Chapman Ranch Field Acquisitions - - On September 21, 2005, the Company executed two separate and definitive agreements for 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 and (ii) additional working interests in the Chapman Ranch Field owned by two other private companies for an aggregate cash purchase price of approximately $62.8 million (of which $35.8 million is attributable to the stock purchase and $27.0 million is 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 incremental purchase price of $5.2 million (of which $3.0

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million is attributable to the stock purchase and $2.2 million is attributable to the working interest asset purchase) related to the operator obtaining high-cost gas certification on or before January 31, 2006, which would provide for severance tax abatements on the properties acquired. The operator of the properties filed for the abatements and the Company was notified recently that not all of the properties qualified for high-cost gas certification, therefore the incremental purchase price was reduced to $4.8 million in January 2006. On November 30, 2005, the Company paid a portion of the incremental purchase price of $3.9 million when a portion of the properties qualified for the certification and incurred a contingent liability for the remaining balance of $0.9 million, which was paid to the Sellers in the first quarter of 2006. The Company financed the acquisitions through borrowings under its credit facility, the borrowing base of which increased in connection with these transactions and other recent activities since the last redetermination.

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

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

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

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

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

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

Cinco was incorporated on October 26, 2004, therefore no results of operations exist prior to that time. The following unaudited pro forma results for 2004 show the effect on the Company’s consolidated results of operations as if the Cinco transaction had occurred at inception on October 26, 2004. The following unaudited pro forma results for 2005 show the effect on the Company’s consolidated results of operations as if the Cinco transaction had occurred on January 1, 2005. The pro forma results are the result of combining the statement of income for the Company with the statement of income for Cinco 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) conversion of Cinco from Successful Efforts method of accounting to Full Cost, (4) interest expense on added borrowings necessary to finance the acquisition and (5) the related income tax effects of these adjustments based on the applicable statutory rates. The pro forma information is based upon numerous assumptions, and is not necessarily indicative of future results of operations:

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

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.

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

The following unaudited pro forma results for 2004 and 2003 show the effect on the Company’s consolidated results of operations as if the Contango Asset Acquisition had occurred on January 1, 2003. They are the result of combining the statement of income of Edge with the statements of revenues and direct operating expenses for the properties adjusted for (i) the completion of the public offering of common stock to finance the cash purchase price, (ii) assumption of ARO liabilities and accretion expense for the properties acquired, (iii) depletion, depreciation and amortization expense applied to the adjusted basis of the properties acquired using the purchase method of accounting and (iv) the related income tax effects of these adjustments based on the applicable statutory rates. The statements of revenues and direct operating expenses for the Contango Assets exclude all other historical Contango expenses. As a result, certain estimates and judgments were made in preparing the pro forma adjustments, including as to the incremental expenses associated with the Contango Assets. 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,
	2004		2003
	(unaudited)
	(In thousands, except per share amounts)
Revenue	$	89,941	$	65,173
Net income	$	25,011	$	16,370
Net income per common share:
Basic	$	1.47	$	1.19
Diluted	$	1.42	$	1.17

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

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agreement, each share of issued and outstanding common stock of Miller was converted into 1.22342 shares of Edge common stock. Edge issued approximately 2.6 million shares of Edge common stock to the shareholders of Miller in exchange for all of the outstanding common stock of Miller. The merger was treated as a tax-free reorganization and accounted for as a purchase business combination. Under this method of accounting, on the date of the merger, the assets and liabilities of Miller were recorded by Edge at their estimated fair market values.

The following unaudited pro forma results for 2003 show the effect on the Company’s consolidated results of operations as if the Miller transaction occurred on January 1, 2002. They are the result of combining the statement of income for Edge with the statement of income for Miller adjusted for (i) the revenue and costs associated with certain Alabama properties sold by Miller in June of 2003, prior to consummation of the merger, (ii) depletion, depreciation and amortization expense of Miller applied to the adjusted basis of the properties acquired using the purchase method of accounting, and (iii) the related income tax effects of these adjustments based on the applicable statutory rates. The pro forma data presented is based on numerous assumptions and is not necessarily indicative of future results of operations or comparable to actual 2005 and 2004 results of the merged companies.

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

Divestitures - During 2005, the Company had no divestitures of oil and gas properties. During 2004 and 2003, the Company sold oil and gas properties for net proceeds of $60,000 and $330,096, respectively. Proceeds from these dispositions were credited to the full cost pool. The Company’s 2004 asset divestitures related primarily to the sale of certain oil and gas properties and equipment in Texas, Mississippi and Louisiana. The Company’s 2003 asset divestitures related primarily to the sale of the Company’s interest in affiliated entities, Essex I and II Joint Ventures, and certain oil and gas properties in Texas and Louisiana.

7.ASSET RETIREMENT OBLIGATIONS

In June 2001, the FASB issued SFAS No. 143, which requires that 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.

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

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

ARO liabilities incurred during the year ended December 31, 2005 include obligations assumed for 16 wells acquired in the Chapman Ranch Field acquisition, as well as obligations for all successful wells drilled during the year. Liabilities settled during the year ended December 31, 2005 included 20 wells that were either plugged or sold.

8.ACCRUED LIABILITIES

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

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

9.HEDGING AND DERIVATIVE ACTIVITIES

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 oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price 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 also reduces the Company’s potential exposure to adverse price movements. The Company’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit the Company’s potential gains from future increases in prices. None of these instruments are used for trading or speculative purposes. 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.

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. These derivative instruments are intended to hedge our price risk and may be considered hedges for economic purposes, but certain of

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these transactions may not qualify for cash flow hedge accounting. All derivative instrument contracts are recorded on the balance sheet at fair value. For those derivative instrument contracts that 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 and the ineffective portion of the changes in the fair value of the contracts is recorded in revenue as they occur. 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. When the hedged production is sold, the realized gains and losses on the contracts are removed from other comprehensive income and recorded in revenue. The Company is currently accounting for its natural gas contracts as cash flow hedges of future cash flows from the sale of natural gas. For those derivative instrument contracts that either do not qualify for cash flow hedge accounting or the Company does not designate as hedges of future cash flows, the changes in fair value are not deferred through other comprehensive income, but rather recorded in revenue immediately as unrealized gains or losses. The Company did not apply cash flow hedge accounting to its crude oil collars entered into in 2004 and 2005, because although they were economic hedges, they did not qualify for hedge accounting.

For the years ended December 31, 2005, 2004 and 2003, the Company included in revenue realized and unrealized losses related to its natural gas hedges and oil derivatives. There was no ineffectiveness recognized during the years ended December 31, 2005, 2004 and 2003. The impact on total revenue from hedging activities for the three years ended December 31, 2005, 2004 and 2003 was as follows:

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

The outstanding hedges at December 31, 2005 and 2004 impacting the balance sheet were as follows:

							Fair Value of Outstanding Hedging and Derivative Contracts as of
				Price		Volumes	December 31,
Transaction Date	Transaction Type	Beginning	Ending	Per Unit		Per Day	2005			2004(4)
Natural Gas (1):							$			$
05/04	Natural Gas Collar	01/01/2005	03/31/2005	$	5.00-$10.39	10,000MMbtu	—			92,703
07/04	Natural Gas Collar	04/01/2005	06/30/2005	$	5.00-$7.53	10,000MMbtu	—			9,162
07/04	Natural Gas Collar	07/01/2005	09/30/2005	$	5.00-$7.67	10,000MMbtu	—			(41,210		)
10/04	Natural Gas Collar	01/01/2005	12/31/2005	$	6.00-$9.52	10,000MMbtu	—			1,860,375
08/05	Natural Gas Collar	01/01/2006	12/31/2006	$	7.00-$10.50	10,000MMbtu	(2,497,823		)	—
08/05	Natural Gas Collar	01/01/2006	12/31/2006	$	7.00-$16.10	10,000MMbtu	(137,077		)	—
Crude Oil (2):
03/04	Crude Oil Collar	04/01/2004	12/31/2004	$	30.00-$35.50	400Bbl	—			(96,240		)
05/04 (08/04)	Crude Oil Collar(3)	01/01/2005	12/31/2005	$	35.00-$40.00	200/290Bbl	—			(468,308		)
08/05	Crude Oil Collar	01/01/2006	12/31/2006	$	55.00-$80.00	400Bbl	155,865			—-
							$	(2,479,035	)	$	1,356,482

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

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

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

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

10.LONG-TERM DEBT

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

The Credit Facility matures December 31, 2007 and is secured by substantially all of the Company’s assets. Borrowings under the Credit Facility bear interest at a rate equal to prime plus 0.50% or LIBOR plus 2.25%. At December 31, 2005 the interest rate applied to the Company’s outstanding borrowings was 7.5%. As of December 31, 2005, $85.0 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 also prohibits dividends and certain distributions of cash or properties and certain liens. The Credit Facility also contains the following financial covenants, among others:

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

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

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

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

11.SHELF REGISTRATION STATEMENT

During the second quarter 2005, the Company filed a registration statement with the SEC which registered offerings up to $390 million of any combination of debt securities, preferred stock, common stock or

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warrants for debt securities or equity securities of the Company. 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 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. In connection with the filing of the 2005 registration statement, we deregistered the remaining shares then available for sale under our earlier $150 million shelf registration statement filed in 2004.

On December 21, 2004, the Company completed an offering of 3.5 million shares of its common stock, which generated net proceeds of $47.8 million, before direct costs of the offering of $0.6 million. These funds were used to finance the south Texas asset acquisition that closed December 29, 2004 and fund other general corporate purposes. On January 5, 2005, the underwriters exercised their over-allotment option for an additional 525,000 shares of common stock, which generated additional net proceeds of $7.2 million. These funds were used to reduce outstanding debt. Each of these sales was made under the Company’s initial shelf registration statement. At December 31, 2005, the Company had $390 million available for issuance under its 2005 shelf registration statement.

12.COMMITMENTS AND CONTINGENCIES

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

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

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

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.

Texas Comptroller Audit - During the second quarter of 2004, the Company received notice that its franchise tax returns for the State of Texas would be audited for the tax years 1999 through 2002. After reviewing documents submitted, the agent representing the Office of the Comptroller of the State of Texas proposed adjustments to the calculation that would result in an increased franchise tax liability. The agent maintained that transfers by the Company to its subsidiaries that the Company classified as intercompany loans should instead be classified as equity investments in the subsidiary. The State of Texas originally proposed that the franchise tax liability of the subsidiaries would be increased by approximately $3.0 million for the four-year period under audit.

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

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issued a Position Letter reaffirming the auditor’s assessment, and rejecting the Company’s arguments as set forth in its April 21, 2005, request for redetermination. On February 24, 2006, the Company filed a motion to set the matter for oral hearing before an Administrative Law Judge. Prior to the oral hearing the Company will submit additional written materials to the Hearings Attorney. The Company intends to continue to vigorously contest the assessment through appropriate administrative levels in the Comptroller’s Office and any other available means. Due to its intention to continue to vigorously contest the proposed adjustments, the Company has not recognized any provision for the additional franchise taxes that would result from the proposed deficiency.

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

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

The Company may have insurance coverage for all or part of this claim up to the $2.0 million limit of the policy. A claim was submitted to the Company’s casualty carrier, who is currently providing a defense under a reservation of rights letter. The Company believes that it would only be liable for its 2.8% share of any damage award unless a co-party defendant cannot satisfy its share of any final judgment. The Company intends to continue to vigorously contest this suit. The Company has not established any reserve with respect to these claims.

13.SALES TO MAJOR CUSTOMERS AND OPERATORS

In accordance with Statement of Financial Accounting Standards No. 131 (“SFAS No. 131”), Disclosures about Segments of an Enterprise and Related Information, public business enterprises are required to report financial and

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

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

* Zero or less than 1%

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

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

In the exploration, development and production business, production is normally sold to relatively few customers. A significant portion of our sales are made on our 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, we believe that the loss of any of our major purchasers would not have a long-term material adverse effect on our operations.

14.INCOME TAXES

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, 2005 and 2004 are as follows:

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

F-24

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

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

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

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

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

At December 31, 2005, the Company had cumulative net operating loss carryforwards (“NOLs”) for federal income tax purposes of approximately $55.8 million that expire beginning 2020 through 2024. The Company believes that it is more likely than not that it will utilize all of these NOLs in connection with federal income taxes generated in the future. The estimated NOLs 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.

15.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, 2005, 2004 and 2003, the Company contributed approximately $176,500, $121,300, and $74,200, respectively, to the Plan.

16.EQUITY AND STOCK PLANS

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

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Public Offering - - In connection with a public offering on December 21, 2004, the Company issued 3,500,000 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 525,000 additional shares of common stock, resulting in an additional $7.2 million of net proceeds to the Company.

Stock Plans - In conjunction with the Offering, the Company established the Incentive Plan of Edge Petroleum Corporation (the “Incentive Plan”). 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 2-3 years. The Company amended the Incentive Plan in December 2003, to increase the shares available under the plan from 1.2 million to 1.7 million. An aggregate of 1,700,000 shares of common stock have been reserved for grants under the Incentive Plan, of which 355,224 shares were available for future grants at December 31, 2005. The following nonqualified stock option awards and restricted stock grants were made under the Incentive Plan during each of the years indicated below:

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

Stock option awards issued to date vest 100% two years from date of grant. 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 years in accordance with the award’s vesting schedule, beginning on the first anniversary of the date of grant. Compensation expense from restricted stock is amortized over the vesting period and offset to additional paid in capital. Below is a summary of amortization of deferred compensation related to restricted stock awards for the years indicated:

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

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

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Deferred compensation cost reported in accordance with FIN 44 (see Note 2 above) included a charge for the year ended December 31, 2005. Below is a summary of FIN 44 charges related to the variable accounting for certain re-priced stock options impacting the Company’s statement of operations for the years indicated:

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

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 some options and restricted stock under the Incentive Plan. The options vest and become exercisable over a two or three year period subsequent to issue. The restricted stock is issued ratably over three years in accordance with the award’s vesting schedule, beginning on the first anniversary of the date of grant. Compensation expense is amortized over the vesting period and offset to additional paid in capital. The amortization of compensation expense related to this award was included in the amounts discussed above. Below is a summary of option and restricted stock grants to Mr. Elias made outside of the Incentive Plan:

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

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

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

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A summary of the status of the Company’s stock options and changes as of and for each of the three years ended December 31, 2005 is presented below:

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

* No options were granted in 2005.

A summary of the Company’s stock options categorized by class of grant at December 31, 2005 is presented below:

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

Computation of Earnings per Share - The following is presented as a reconciliation of the numerators and denominators of basic and diluted earnings per share computations, in accordance with SFAS No. 128.

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

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

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

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

17.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.

Affiliates’ Ownership in Prospects – Edge Group Partnership, Edge Holding Company, L.P., a limited partnership of which Mr. Sfondrini and a corporation wholly owned by him are the general partners, Andex Energy Corporation and Texedge Energy Corporation, corporations of which Mr. Andrews is an officer and members of his immediate family hold ownership interests, Mr. Raphael, Jovin, L.P. (a limited partnership, the general partners of which are a company wholly owned by Mr. Sfondrini and a company of which Mr. Andrews is an officer) and Essex II 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. The gross amounts paid or accrued to these persons and entities by the Company in 2005 (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:

F-29

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

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

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

A summary of non-cash investing and financing activities for the years ended December 31, 2005, 2004 and 2003 is presented below:

Description	Number of shares issued	Fair Market Value
2005:
Shares issued to satisfy restricted stock grants	59,295	$	569,724
Shares issued to fund the Company’s matching contribution under the Company’s 401(k) plan	9,980	$	167,616
2004:
Shares issued to satisfy restricted stock grants	70,463	$	446,881
Shares issued to fund the Company’s matching contribution under the Company’s 401(k) plan	7,500	$	111,797
2003:
Shares issued to satisfy restricted stock grants	75,095	$	395,192
Shares issued to fund the Company’s matching contribution under the Company’s 401(k) plan	14,475	$	69,375
Shares issued in Miller merger	2,604,757	$	14,421,051

Supplemental Disclosure of Cash Flow Information

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

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19.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			Second Quarter			First Quarter
	(in thousands, except per share amounts)
2005:
Oil and natural gas revenue	$	42,444		$	29,585		$	26,210		$	22,944
Operating expenses	(21,943		)	(17,083		)	(15,056		)	(15,640		)
Operating income	20,501			12,502			11,154			7,304
Other expense, net	(3		)	(8		)	(11		)	(3		)
Income tax expense	(7,216		)	(4,351		)	(3,934		)	(2,577		)
Net income	$	13,282		$	8,143		$	7,209		$	4,724
Basic earnings per share	$	0.78		$	0.47		$	0.42		$	0.28
Diluted earnings per share	$	0.75		$	0.45		$	0.41		$	0.27
2004:
Oil and natural gas revenue	$	19,601		$	13,242		$	15,847		$	15,815
Operating expenses	(11,293		)	(9,035		)	(9,755		)	(10,601		)
Operating income	8,308			4,207			6,092			5,214
Other expense, net	(105		)	(50		)	(142		)	(140		)
Income tax expense	(2,896		)	(1,474		)	(2,094		)	(1,791		)
Net income	$	5,307		$	2,683		$	3,856		$	3,283
Basic earnings per share	$	0.39		$	0.21		$	0.30		$	0.26
Diluted earnings per share	$	0.38		$	0.20		$	0.28		$	0.25

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

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:

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

F-31

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

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

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

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

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:

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

Reserves - Proved reserves are estimated quantities 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 net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves, all of which are located in the continental United States, are summarized below.

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

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

Standardized Measure - TheStandardized 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, 2005 is shown below:

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

In accordance with SEC regulations, the year-end oil and natural gas prices in effect at December 31, 2005, 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 $10.05 per MMbtu of natural gas, $36.62 per Bbl of natural gas liquids and $61.04 per Bbl of oil. In the normal course of business the Company enters into hedging transactions, including commodity price collars, swaps and floors to mitigate exposure to commodity price movements, but not for trading or speculative purposes. During 2005, the Company put in place several natural gas and crude oil collars for a portion of its 2006 production to achieve a more predictable cash flow. As of December 31, 2005, hedge contracts cover approximately 48% and 37% of anticipated 2006 natural gas and crude oil production, respectively, before any future acquisitions. The prices used in calculating the standardized measure fall within the limits of all the hedge transaction collars, therefore there would be no impact to the standardized measure by these hedge transactions.

F-33

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.

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

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

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-34

INDEX TO EXHIBITS

Exhibit No.
2.1	—	Amended and Restated Combination Agreement by and among (i) Edge Group II Limited Partnership, (ii) Gulfedge Limited Partnership, (iii) Edge Group Partnership, (iv) Edge Petroleum Corporation, (v) Edge Mergeco, Inc. and (vi) the Company, dated as of January 13, 1997 (Incorporated by reference from exhibit 2.1 to the Company’s Registration Statement on Form S-4 (Registration No. 333-17269)).
2.2	—	Agreement and Plan of Merger dated as of May 28, 2003 among Edge Petroleum Corporation, Edge Delaware Sub Inc. and Miller Exploration Company (Miller”) (Incorporated by reference from Annex A to the Joint Proxy Statement/Prospectus contained in the Company’s Registration Statement on Form S-4/A filed on October 31, 2003 (Registration No. 333-106484)).
2.3	—	Asset Purchase Agreement by and among Contango STEP, L.P., Contango Oil & Gas Company, Edge Petroleum Exploration Company and Edge Petroleum Corporation, dated as of October 7, 2004 (Incorporated by reference from exhibit 2.1 to the Company’s Current Report on Form 8-K filed October 12, 2004).
2.4	—	Purchase and Sale Agreement, dated as of September 21, 2005 among Pearl Energy Partners, Ltd., and Cibola Exploration Partners, L.P., as Sellers; and Edge Petroleum Exploration Company as Buyer and Edge Petroleum Corporation as Guarantor (Incorporated by reference from exhibit 2.1 to the Company’s Current Report on Form 8-K filed October 19, 2005).
2.5	—	Stock Purchase Agreement by and among Jon L. Glass, Craig D. Pollard, Leigh T. Prieto, Yorktown Energy Partners V, L.P., Yorktown Energy Partners VI, L.P., Cinco Energy Corporation, and Edge Petroleum Exploration Company and Edge Petroleum Corporation, dated as of September 21, 2005 (Incorporated by reference from exhibit 2.5 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2005).
2.6	—	Letter Agreement dated November 18, 2005 by and among Edge Petroleum Exploration Company, Cinco Energy Corporation and Sellers (Incorporated by reference from exhibit 2.02 to the Company’s Current Report on Form 8-K filed December 6, 2005). Pursuant to Item 601(b)(2) of Regulation S-K, the Company had omitted certain Schedules to the Letter Agreement (all of which are listed therein) from this Exhibit 2.6. It hereby agrees to furnish a supplemental copy of any such omitted item to the SEC on its request.
3.1	—	Restated Certificate of Incorporation of the Company effective January 27, 1997 (Incorporated by reference from exhibit 3.1 to the Company’s Current Report on Form 8-K filed April 29, 2005).
3.2	—	Certificate of Amendment to the Restated Certificate of Incorporation of the Company effective January 31, 1997 (Incorporated by reference from exhibit 3.2 to the Company’s Current Report on Form 8-K filed April 29, 2005).
3.3	—	Certificate of Amendment to the Restated Certificate of Incorporation of the Company effective April 27, 2005 (Incorporated by reference from exhibit 3.3 to the Company’s Current Report on Form 8-K filed April 29, 2005).
3.4	—	Bylaws of the Company (Incorporated by Reference from exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).

F-35

3.5	—	First Amendment to Bylaws of the Company on September 28, 1999 (Incorporated by Reference from exhibit 3.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2003).
3.6	—	Second Amendment to Bylaws of the Company on May 7, 2003 (Incorporated by reference from exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).
4.1	—	Third Amended and Restated Credit Agreement dated December 31, 2003 among Edge Petroleum Corporation, Edge Petroleum Exploration Company, Edge Petroleum Operating Company, Inc., Miller Oil Corporation, and Miller Exploration Company, as borrowers, the lenders thereto and Union Bank of California, N.A., a national banking association, as Agent (Incorporated by reference from Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).
4.2	—	Agreement and Amendment No. 1 to Third Amended and Restated Credit Agreement dated May 31, 2005 among Edge Petroleum Corporation, Edge Petroleum Exploration Company, Edge Petroleum Operating Company, Inc., Miller Exploration Company and Miller Oil Corporation, as borrowers, the lenders thereto and Union Bank of California, N.A., a national banking association, as agent for the lenders (Incorporated by reference from Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2005).
*4.3	—	Agreement and Amendment No. 2 to the Third Amended and Restated Credit Agreement dated November 30, 2005 among Edge Petroleum Corporation, Edge Petroleum Exploration Company, Edge Petroleum Operating Company, Inc., Miller Oil Corporation, Miller Exploration Company, and Cinco Energy Corporation, as borrowers, the lenders thereto and Union Bank of California, N.A., a national banking association, as Agent.
4.4	—	Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference from exhibit 10.1(a) to Miller Exploration Company’s Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 000-23431)).
4.5	—	Amendment No. 1 to the Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference to Exhibit 4.2 from Miller Exploration Company’s Registration Statement on Form S-8 filed on April 11, 2001 (Registration No. 333-58678)).
4.6	—	Amendment No. 2 to the Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference from Exhibit 4.3 to Miller Exploration Company’s Registration Statement on Form S-8 filed on April 11, 2001 (Registration No. 333-58678)).
4.7	—	Form of Miller Stock Option Agreement (Incorporated by reference from exhibit 10.1(b) to Miller Exploration Company’s Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 000-23431)).
†10.1	—	Form of Indemnification Agreement between the Company and each of its directors (Incorporated by reference from exhibit 10.7 to the Company’s Registration Statement on Form S-4 (Registration No. 333-17269)).
†10.2	—	Stock Option Plan of Edge Petroleum Corporation, a Texas corporation (Incorporated by reference from exhibit 10.13 to the Company’s Registration Statement on Form S-4 (Registration No. 333-17269)).

F-36

†10.3	—	Employment Agreement dated as of November 16, 1998, by and between the Company and John W. Elias (Incorporated by reference from 10.12 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998).
†10.4	—	Incentive Plan of Edge Petroleum Corporation as Amended and Restated Effective as of June 1, 2004 (Incorporated by reference from exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004).
†10.5	—	Edge Petroleum Corporation Incentive Plan “Standard Non-Qualified Stock Option Agreement” by and between Edge Petroleum Corporation and the Officers named therein (Incorporated by reference from exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).
†10.6	—	Edge Petroleum Corporation Incentive Plan “Director Non-Qualified Stock Option Agreement” by and between Edge Petroleum Corporation and the Directors named therein (Incorporated by reference from exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).
†10.7	—	Severance Agreements by and between Edge Petroleum Corporation and the Officers of the Company named therein (Incorporated by reference from exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).
†10.8—		Form of Director’s Restricted Stock Award Agreement under the Incentive Plan of Edge Petroleum Corporation (Incorporated by reference from exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004).
†10.9	—	Form of Employee Restricted Stock Award Agreement under the Incentive Plan of Edge Petroleum Corporation (Incorporated by reference from exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q/A for the quarterly period ended March 31, 1999).
†10.10	—	Edge Petroleum Corporation Amended and Restated Elias Stock Incentive Plan. (Incorporated by reference from exhibit 4.5 to the Company’s Registration Statement on Form S-8 filed May 30, 2001 (Registration No. 333-61890)).
†10.11	—	Form of Edge Petroleum Corporation John W. Elias Non-Qualified Stock Option Agreement (Incorporated by reference from exhibit 4.6 to the Company’s Registration Statement on Form S-8 filed May 30, 2001 (Registration No. 333-61890)).
*†10.12	—	Summary of Compensation of Non-Employee Directors.
*†10.13	—	Salaries and Other Compensation of Executive Officers.
*†10.14	—	Description of 2005 Bonus Program for Executive Officers.
*21.1	—	Subsidiaries of the Company.
*23.1	—	Consent of BDO Seidman, LLP.
*23.2	—	Consent of Ryder Scott Company.
*23.3	—	Consent of W.D. Von Gonten & Co.

F-37

*31.1	—	Certification by John W. Elias, Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
*31.2	—	Certification by Michael G. Long , Chief Financial and Accounting Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
*32.1	—	Certification by John W. Elias, Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
*32.2	—	Certification by Michael G. Long, Chief Financial and Accounting Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
*99.1	—	Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 2005.
*99.2	—	Summary of Reserve Report of W. D. Von Gonten & Co. Petroleum Engineers as of December 31, 2005.

* Filed herewith.

^† Denotes management or compensatory contract, arrangement or agreement.

F-38

EX-4.3

EXHIBIT 4.3

AGREEMENT, CONSENT AND AMENDMENT NO. 2 TO THIRD AMENDED

AND RESTATED CREDIT AGREEMENT

This AGREEMENT, CONSENT AND AMENDMENT NO. 2 TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT (“Agreement”) dated as of November 30, 2005 (the “Effective Date”) is among Edge Petroleum Corporation, a Delaware corporation (“Parent”), Edge Petroleum Exploration Company, a Delaware corporation (“Edge Exploration”), Edge Petroleum Operating Company, Inc., a Delaware corporation (“Edge Operating”) Miller Exploration Company, a Delaware corporation (“Miller Exploration”), and Miller Oil Corporation, a Michigan corporation (“Miller Operating”) and Cinco Energy Corporation, a Delaware corporation (“Cinco Energy”, and together with the Parent, Edge Exploration, Edge Operating, Miller Exploration and Miller Operating referred to collectively as the “Borrowers”), the lenders party to the Credit Agreement (as defined below) from time to time (the “Lenders”), and Union Bank of California, N.A., as agent for the Lenders (“Agent”).

RECITALS

A.The Borrowers (other than Cinco Energy), the Lenders and the Agent are parties to the Third Amended and Restated Credit Agreement dated as of December 31, 2003, as amended by the Agreement and Amendment No. 1 to Third Amended and Restated Credit Agreement dated as of May 31, 2005 (as so amended, the “Credit Agreement”; the defined terms of which are used herein unless otherwise defined herein).

B.The Borrowers, the Lenders and the Agent wish to, subject to the terms and conditions of this Agreement:  (1) consent to the transactions contemplated by the Cinco Energy Acquisition Agreement (each as defined below), (2) increase the Commitments, (3) increase the Borrowing Base, (4) add Cinco Energy as a Borrower, and (5) make such other amendments to the Credit Agreement as provided herein.

THEREFORE, in consideration of their mutual undertakings, the Borrowers, the Lenders and the Agent hereby agree as follows:

Section 1.Defined Terms; Other Definitional Provisions. As used in this Agreement, each of the terms defined in the opening paragraph and the Recitals above shall have the meanings assigned to such terms therein.The words “hereby”, “herein”, “hereinafter”, “hereof”, “hereto” and “hereunder” when used in this Agreement shall refer to this Agreement as a whole and not to any particular Article, Section, subsection or provision of this Agreement. All titles or headings to Articles, Sections, subsections or other divisions of this Agreement or the exhibits hereto, if any, are only for the convenience of the parties and shall not be construed to have any effect or meaning with respect to the other content of such Articles, Sections, subsections, other divisions or exhibits, such other content being controlling as the agreement among the parties hereto. Whenever the context requires, reference herein made to the single number shall be understood to include the plural; and likewise, the plural shall be understood to include the singular. Words denoting sex shall be construed to include the masculine, feminine

and neuter, when such construction is appropriate; and specific enumeration shall not exclude the general but shall be construed as cumulative.

Section 2.Consent to Acquisition. Subject to the terms of this Agreement, the Lenders hereby consent to the consummation of the transactions contemplated by the Stock Purchase Agreement dated as of September 21, 2005 (the “Cinco Energy Acquisition Agreement”) with Jon L. Glass, Craig D. Pollard, Leigh T. Prieto, Yorktown Energy Partners V, L.P. and Yorktown Energy Partners VI, L.P. relating to the sale of all of the outstanding capital stock of Cinco Energy to Edge Exploration, as buyer, and the Parent, as guarantor. The consent by the Lenders described in the preceding sentence is contingent upon the satisfaction of the conditions precedent set forth below in this Agreement and is strictly limited to the extent described herein. Nothing contained herein shall be construed to be a consent to or a permanent waiver of any terms, provisions, covenants, warranties or agreements contained in the Credit Agreement or in any of the other Loan Documents. The Lenders reserve the right to exercise any rights and remedies available to them in connection with any present or future defaults with respect to the Credit Agreement or any other provision of any Loan Document.

Section 3.Addition of Cinco Energy as a Borrower. As of the date hereof, Cinco Energy agrees to perform and observe, each and every one of the covenants, rights, promises, agreements, terms, conditions, obligations, appointments, duties and liabilities of a “Borrower” under the Credit Agreement and all other Loan Documents. By virtue of the foregoing, Cinco Energy hereby accepts and assumes any liability of the Borrowers related to each representation, warranty, covenant or obligation made by any of the Borrowers in the Credit Agreement or any other Loan Document, and hereby expressly affirms, as of the date hereof, each of such representations and warranties and such covenants and obligations in the Credit Agreement. All references to the term “Borrower” or “Borrowers” in the Credit Agreement or in any other Loan Document, or in any document or instrument executed and delivered or furnished, or to be executed and delivered or furnished in connection with the Credit Agreement, shall be deemed to include Cinco Energy. Cinco Energy further acknowledges that the obligations of each of the Borrowers (including Cinco Energy) under the Credit Agreement and the Notes are joint and several pursuant to Section 5.23(a) of the Credit Agreement.

Section 4.Increase in Borrowing Base. The Borrowing Base shall, effective as of the Effective Date and subject to the terms herein, be increased from $70,000,000.00 to $110,000,000.00. Such new Borrowing Base shall remain in effect at that level until the Borrowing Base is redetermined in accordance with the terms of the Credit Agreement.

Section 5.Amendments to the Credit Agreement.

(a)The title page of the Credit Agreement shall be amended to replace the existing Commitment amount of $100,000,000 with the new Commitment amount of $150,000,000.

(b)Section 1.2 of the Credit Agreement is hereby amended by replacing the definitions of “Commitment” and “Financial Statements” in their entirety with the following:

“Commitment” shall mean, for each Lender, the amount set opposite such Lender’s name on Schedule 2 hereof as its Commitment or, if such Lender has

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entered into any Lender Assignment Agreement after the date of this Agreement, the amount set forth for such Lender as its Commitment in the Register maintained by the Agent pursuant to Section 9.1(c), as such amount may be reduced pursuant to Section 2.12.

“Financial Statements” shall mean statements of the financial condition of the Parent and its consolidated Subsidiaries on a consolidated, and if requested by the Agent, consolidating basis as at the point in time and for the period indicated and consisting of at least a balance sheet and related statements of operations, common stock and other stockholders’ equity, and cash flows, and when such statements prepared on a consolidated basis are required by applicable provisions of this Agreement to be audited, accompanied by the unqualified certification of a nationally-recognized firm of independent certified public accountants or other independent certified public accountants acceptable to the Agent and footnotes to any of the foregoing, all of which shall be prepared in accordance with GAAP consistently applied from quarter to quarter (except for any inconsistency that results from a change in GAAP) and consistently applied within each set of Financial Statements and in comparative form with respect to the corresponding period of the preceding fiscal period.

(c)Section 1.2 of the Credit Agreement is hereby further amended by inserting the following new definition in alphabetical order:

“Fee Letter” means that certain fee letter dated as of November 30, 2005 between the Borrowers and the Agent.

(d)Section 2.14 of the Credit Agreement is hereby amended by replacing the existing Section 2.14 in its entirety with the following:

2.14Other Fees. The Borrowers agree to pay to the Agent the fees as described in the Fee Letter.

(e)The reference to .50% in the second sentence of Section 2.15 of the Credit Agreement is hereby deleted and replaced with .35%.

(f)Section 5.2 of the Credit Agreement is hereby amended by replacing the existing Section 5.2 in its entirety with the following:

5.2Quarterly Financial Statements; Compliance Certificates.  Cause the Parent to deliver to the Agent and each Lender, (a) on or before the 45th day after the close of each of the first three quarterly periods of each fiscal year of the Parent, a copy of the unaudited consolidated, and if requested by the Agent,  consolidating Financial Statements of the Parent and its consolidated Subsidiaries as at the close of such quarterly period and from the beginning of such fiscal year to the end of such period, such Financial Statements to be certified by a Responsible Officer of the Parent (i) as having been prepared in accordance with GAAP consistently applied from quarter to quarter (except for any inconsistency that results from a change in GAAP) and consistently applied within each set of

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Financial Statements and (ii)as a fair presentation of the condition of the Parent, subject to changes resulting from normal year-end audit adjustments, and (b) on or before the 45th day after the close of each fiscal quarter of the Parent and on or before the 90th day after the close of each fiscal year of the Parent, a Compliance Certificate in the form of Exhibit B hereto signed by a Responsible Officer of the Parent.

(g)Section 5.3 of the Credit Agreement is hereby amended by replacing the existing Section 5.3 in its entirety with the following:

5.3Annual Financial Statements. Cause the Parent to deliver to the Agent and each Lender, on or before the 90th day after the close of each fiscal year of the Parent, a copy of the annual audited consolidated, and if requested by the Agent,  unaudited consolidating Financial Statements of the Parent.

(h)Clause (j) of Section 6.8 of the Credit Agreement is hereby deleted and replaced in its entirety with the following new clause (j):

and (j) acquisitions of Oil and Gas Properties;

(i)The Schedule 2 to this Agreement is hereby added as new Schedule 2 to the Credit Agreement.

(j)Schedule 4.21 to the Credit Agreement is hereby deleted and replaced in its entirety with new Schedule 4.21 to this Agreement.

Section 6.Representations and Warranties. The Borrowers hereby represent and warrant that:  (a)  except for such representations which are made only as of a prior date, the representations and warranties set forth in the Credit Agreement and in the other Loan Documents are true and correct in all material respects as of the Effective Date as if made on and as of such date; (b) the execution, delivery and performance of this Agreement and any Loan Documents executed and delivered in connection with this Agreement are within the corporate power and authority of each Borrower and have been duly authorized by appropriate corporate action and proceedings; (c) this Agreement and the Loan Documents executed in connection with this Agreement constitute legal, valid, and binding obligations of the Borrowers party hereto and thereto, enforceable in accordance with their terms, except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, or similar laws affecting the rights of creditors generally and general principles of equity; and (d) there are no governmental or other third party consents, licenses and approvals required in connection with the execution, delivery, performance, validity and enforceability of this Agreement and such other Loan Documents.

Section 7.Conditions. This Agreement shall become effective and enforceable against the parties hereto, the Credit Agreement shall be amended as provided herein, and the Borrowing Base increase provided herein shall become effective upon the occurrence of the following conditions precedent on or before the Effective Date:

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(a)Agreement. The Agent shall have received multiple original counterparts of this Agreement duly and validly executed and delivered by duly authorized officers of the Borrowers, the Agent and the Lenders.

(b)New Notes. The Borrowers shall have executed and delivered amended and restated Notes dated the date hereof to each of the Lenders in an amount equal to each such Lender’s respective new Commitment.

(c)Mortgage Supplements. The Agent shall have received original new Mortgages and supplements to existing Mortgages, providing for the mortgaging of certain additional Oil and Gas Properties and reflecting the increase in the Commitments to an aggregate amount of $150,000,000, and otherwise, in form and substance satisfactory to the Agent, duly and validly executed and delivered by duly authorized officers of the Borrowers, the Agent and the Lenders.

(d)Acquisition Documents. The Agent shall have received copies, certified by a Responsible Officer of Edge Exploration, of the Cinco Energy Acquisition Agreement, and all other documents, agreements, instruments and amendments thereto.

(e)Consummation of the Cinco Energy Acquisition Agreement. All conditions to the consummation and effectiveness of the transactions contemplated by the Cinco Energy Acquisition Agreement shall have been met on or prior to November 30, 2005, and the aggregate purchase price (including any debt assumed or issued (other than pursuant to the Credit Agreement) but excluding any purchase price adjustments resulting from cash or cash equivalents remaining with the sellers or other adjustments to the purchase price or provided in the Cinco Energy Acquisition Agreement) for the Cinco Energy Acquisition Agreement shall not exceed $38,000,000, and after giving effect to any of the aforementioned adjustments, shall not exceed $43,500,000.

(f)Supplement to Second Amended and Restated Security Agreement. The Agent shall have received original counterparts of the Supplement No. 1 to the Second Amended and Restated Security Agreement executed by Cinco Energy and the Agent covering all personal property of Cinco Energy.

(g)Amendment to Second Amended and Restated Security Agreement (Stock Pledge). The Agent shall have received original counterparts of the Amendment No. 1 to the Second Amended and Restated Security Agreement (Stock Pledge) executed by Edge Exploration and the Agent listing the newly pledged collateral covering all of the issued and outstanding capital stock of Cinco Energy and other personal property related thereto.

(h)Cinco Energy Stock Certificates & Powers. The Agent shall have received Irrevocable Stock Powers executed in blank by Edge Exploration and the stock certificates for the stock of Cinco Energy pledged under the Second Amended and Restated Security Agreement (Stock Pledge).

(i)Fee Letter. The Agent shall have received original counterparts of the Fee Letter duly and validly executed by the Borrowers and the Agent.

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(j)Secretary’s Certificate. The Agent shall have received copies, certified as of the date hereof by a secretary or an assistant secretary of each of the Borrowers and any Guarantor, of (A) the corporate resolutions duly adopted at a meeting or by unanimous consent of the board of directors of such Borrower or such Guarantor approving the increase in the Commitments, the execution of new Notes and authorizing the transactions contemplated herein, (B) the Certificate of Incorporation and all amendments thereto and the bylaws and all amendments thereto of each of the Borrowers and any Guarantor, and (C) all other documents evidencing other necessary corporate action and governmental approvals, if any, with respect to this Agreement.

(k)Good Standing & Existence Certificates. The Agent shall have received certificates dated as of a recent date from the Secretary of State or other appropriate Governmental Authority evidencing the existence or qualification and good standing of each of the Borrowers in its jurisdiction of incorporation and in any other jurisdiction where such qualification is required by applicable law.

(l)Legal Opinion. The Agent shall have received the opinion of Robert C. Thomas in form and substance reasonably acceptable to the Agent.

(m)Other Instruments or Documents. The Agent and the Lenders shall have received duly executed new Security Instruments and such other instruments, documents and attachments to existing Security Instruments as any of them may reasonably request.

(n)No Default. No Default shall have occurred and be continuing as of the Effective Date.

(o)Fees. The Borrowers shall have paid a Borrowing Base Increase Fee in an aggregate amount equal to 0.35% of the increased availability under the Borrowing Base to the Lenders, which amount when calculated equals $140,000. Such fee shall be shared by the Lenders as follows: (i) to BNP Paribas, the amount of $17,500, (ii) to Compass Bank, the amount of $70,000, and (iii) to The Frost National Bank, the amount of $52,500. Such Borrowing Base Increase Fee shall be paid on the Effective Date and shall, once paid be nonrefundable. Additionally, the Borrower shall have paid (i) the Agency Fee described in the Fee Letter, and (ii) all fees and expenses of the Agent’s outside legal counsel and other consultants pursuant to all invoices presented for payment on or prior to the Effective Date.

Section 8.Miscellaneous.

(a)Effect on Loan Documents. Each of the Borrowers, the Lenders and the Agent does hereby adopt, ratify, and confirm the Credit Agreement, as amended hereby and acknowledges and agrees that the Credit Agreement, as amended hereby, is and remains in full force and effect. Nothing herein shall act as a waiver of any of the Agent’s or the Lender’s rights under the Loan Documents, as amended. From and after the Effective Date, all references to the Credit Agreement and the Loan Documents shall mean such Credit Agreement and such Loan Documents, as amended hereby. This Agreement is a Loan Document for the purposes of the provisions of the other Loan Documents. Without limiting the foregoing, any breach of representations, warranties, and covenants under this Agreement shall be an Event of Default under the Credit Agreement.

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(b)New Lenders. Compass Bank and The Frost National Bank are hereby added as new Lenders under the Credit Agreement. Both Compass Bank and The Frost National Bank, by executing this Agreement, (a) confirm that they have received a copy of the Credit Agreement together with any financial statements needed, and such other documents and information as they have deemed appropriate to make its own credit analysis and decision to enter into this Agreement; (b) agree that they will, independently and without reliance upon the Agent, or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Credit Agreement or any other Loan Document; (c) appoint and authorize the Agent to take such action as agent on behalf and to exercise such powers under the Credit Agreement and any other Loan Document as are delegated to the Agent by the terms thereof, together with such powers as are reasonably incidental thereto; and (d) agree that they will perform in accordance with their terms, all of the obligations which by the terms of the Credit Agreement and any other Loan Document are required to be performed by it as a Lender.

(c)Counterparts. This Agreement may be signed in any number of counterparts, each of which shall be an original and all of which, taken together, constitute a single instrument. This Agreement may be executed by facsimile signature and all such signatures shall be effective as originals.

(d)Successors and Assigns. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted pursuant to the Credit Agreement.

(e)Invalidity. In the event that any one or more of the provisions contained in this Agreement shall for any reason be held invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision of this Agreement.

(f)Governing Law. This Agreement shall be deemed to be a contract made under and shall be governed by and construed in accordance with the laws of the State of Texas.

THIS AGREEMENT, THE CREDIT AGREEMENT, THE NOTES, AND THE OTHER LOAN DOCUMENTS CONSTITUTE THE ENTIRE UNDERSTANDING AMONG THE PARTIES HERETO WITH RESPECT TO THE SUBJECT MATTER HEREOF AND SUPERSEDE ANY PRIOR AGREEMENTS, WRITTEN OR ORAL, WITH RESPECT THERETO.

[SIGNATURES BEGIN ON NEXT PAGE]

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EXECUTED effective as of the date first above written.

BORROWERS:
EDGE PETROLEUM CORPORATION
EDGE PETROLEUM EXPLORATION COMPANY
EDGE PETROLEUM OPERATING COMPANY, INC.
MILLER OIL CORPORATION
MILLER EXPLORATION COMPANY
CINCO ENERGY CORPORATION
All by:		/S/ MICHAEL G. LONG
		Michael G. Long, Chief Financial Officer
AGENT AND LENDERS:
UNION BANK OF CALIFORNIA, N.A., as
Agent and as a Lender
By:	/S/ DAMIEN MEIBURGER
	Damien Meiburger
	Senior Vice President

BNP PARIBAS, as a Lender
By:	/S/ DAVID DODD
Name:					DAVID DODD
Title:					DIRECTOR
By:		/S/ BETSY JOCHER
Name:			BETSY JOCHER
Title:				VICE PRESIDENT

COMPASS BANK, as a Lender
By:	/S/ DOROTHY MARCHAND
Name:		DOROTHY MARCHAND
Title:		SENIOR VICE PRESIDENT

THE FROST NATIONAL BANK, as a Lender
By:	/S/ ANDREW A. MERRYMAN
Name:		ANDREW A. MERRYMAN
Title:		SENIOR VICE PRESIDENT

Schedule 2

COMMITMENTS

Each of the commitments to lend set forth herein is governed by the terms of the Credit Agreement which provides for, among other things, borrowing base limitations which may restrict Borrowers’ ability to request (and the Lenders’ obligation to provide) Loans to a maximum amount which is less than the commitments set forth in this Schedule 2.

Lenders	Commitments
Union Bank of California, N.A.	$	57,272,728
BNP Paribas	$	45,000,000
Compass Bank	$	27,272,727
The Frost National Bank	$	20,454,545
Total:	$	150,000,000.00

SCHEDULE 4.21

SUBSIDIARIES

Edge Petroleum Corporation:

Edge Petroleum Exploration Company

Miller Exploration Company

Edge Petroleum Exploration Company:

Edge Petroleum Operating Company, Inc.

Cinco Energy Corporation

Edge Petroleum Operating Company, Inc.:

None

Miller Exploration Company:

Miller Oil Corporation

Miller Oil Corporation:

None

EX-10.12

Exhibit 10.12

SUMMARY OF COMPENSATION OF NON-EMPLOYEE DIRECTORS

Upon recommendation by the Corporate Governance/Nominating Committee and approval by the Board of Directors at its April 2005 meeting, effective May 1, 2005, the annual compensation for Non-employee Directors was revised to increase the annual retainer, which is paid in arrears. In accordance with the new annual compensation arrangement, Non-employee Directors are paid an annual retainer equal to the sum of (1) $20,000 (paid in cash) and (2) $36,000 payable in Common Stock of the Company valued as of the award date (subject to rounding up or down such that the number of shares issued to each director is evenly divisible by three). Accordingly, each Non-employee Director then serving was awarded 2,505 restricted shares of Common Stock on May 2, 2005. The shares vest ratably over three years beginning on the first anniversary of the grant date. The fair market value of the shares on the May 2, 2005 award date was $35,972 per Non-employee Director. No option awards were made to Non-employee Directors in 2005.

In addition, effective May 1, 2005, the amount each Non-employee Director receives for in-person attendance at a meeting of the Board of Directors was increased from $1,000 to $1,500 cash (increased from $400 to $500 if such attendance is telephonic) and was increased from $750 to $1,500 cash for each meeting of a standing Committee of the Board of Directors attended (increased from $400 to $500 if telephonic). The chairman of the Audit Committee will receive an additional annual retainer of $10,000 and the respective chairmen of the Compensation and the Corporate Governance/Nominating Committees will each receive an additional annual retainer of $5,000, such amounts payable for the first time at the annual shareholders meeting in 2005.

On March 9, 2006, the Board approved the following recommendations of the Corporate Governance/Nominating Committee and Compensation Committee of the Board.  On March 9, 2006, the Corporate Governance/Nominating Committee of the Board recommended certain changes to the compensation of non-employee directors of the Company.  The Committee recommended that effective June 1, 2006, the annual retainer, which is payable in arrears, be increased by $14,000 from $56,000 ($20,000 of which is payable in cash and $36,000 of which is payable in common or restricted stock of the Company) to $70,000, consisting of $20,000 payable in cash and $50,000 payable in common or restricted stock of the Company (subject to rounding up or down such that the number of shares issued to each director is evenly divisible by three, but not to exceed $50,000 in value). The Committee also recommended that each director be required to own shares of common stock of the Company equal to three times their annual director compensation and that such ownership be achieved within three years from July 1, 2006.  All directors, except Messrs. Clarkson and Creel, currently own stock in the Company worth at least three times their annual director compensation.

All directors are reimbursed for out-of-pocket expenses incurred in attending meetings of the Board or Board committees and for other expenses incurred in their capacity as directors.

EX-10.13

Exhibit 10.13

SALARIES AND OTHER COMPENSATION OF EXECUTIVE OFFICERS

The table below shows a summary of the amounts of compensation paid to the Company’s executive officers for the last three fiscal years.

							Long Term Compensation
Name and Principal		Annual Compensation (1)					Restricted Stock Awards		Securities Underlying Options	All Other Compensation
Position	Year	Salary		Bonus			(2)		(Shares)	(3)
John W. Elias	2005	$	350,000			(4)	$	141,019	—	$	4,040
Chairman of the Board, President	2004	$	350,000	$	210,000		$	93,852	50,000	$	4,040
and Chief ExecutiveOfficer	2003	$	350,000	$	200,000		—		50,000	$	2,630
Michael G. Long	2005	$	194,625			(4)	$	76,942	—	$	7,000
Executive Vice President	2004	$	178,500	$	109,000		$	47,203	—	$	6,500
and Chief Financial Officer	2003	$	166,700	$	59,000		$	29,808	—	$	6,000
John O. Tugwell	2005	$	199,500			(4)	$	76,942	—	$	7,000
Executive Vice President	2004	$	183,000	$	111,000		$	47,203	—	$	5,935
and Chief Operating Officer	2003	$	172,000	$	59,000		$	29,808	—	$	6,000

(1)Other annual compensation for the named individuals during each of 2005, 2004 and 2003 did not exceed the lesser of $50,000 or 10% of the annual compensation earned by such individual.

(2)Reflects restricted stock awards made pursuant to the Incentive Plan. The dollar value included in the table reflects the valuation at the time of the award. In the case of all restricted stock awards made to executive officers in the last three fiscal years, shares were not issued at the time of the award and instead are issued ratably over three years beginning on the first anniversary of the date of grant, in accordance with the vesting schedule for the award.  Mr.  Elias received awards of 7,110 and 8,583 shares of restricted stock on April 1, 2004 and April 1, 2005, respectively.  Messrs. Long and Tugwell each received awards of 7,200, 3,576 and 4,683 shares of restricted stock on April 1, 2003, April 1, 2004 and April 1, 2005, respectively. Awards of restricted stock, all of which provide that actual shares are

issued only upon vesting, have also been made in prior periods. If actual shares had been issued at grant for the restricted stock awards made in 2005 and all prior periods, the number and value of restricted shares held by the named officers at December 31, 2005 would be as follows: Mr. Elias: 13,323 shares ($331,876); Mr. Long: 9,467 shares ($235,823); and Mr. Tugwell: 9,467 shares ($235,823).

(3)In the case of Mr. Elias, amounts shown represent payments by the Company for life insurance on his account. In the case of Messrs. Long and Tugwell, amounts shown represent the Company’s contributions under its 401(k) Plan. No amounts are included for Mr. Tugwell for payments received by him in respect of overriding royalty interests granted prior to his becoming an executive officer.

(4)The 2005 bonus plan is described in further detail in the “Description of 2005 Bonus Program” filed as Exhibit 10.14 to this Form 10-K and incorporated by reference. The bonus amounts under the 2005 bonus plan will be reported in the 2006 proxy statement.

EX-10.14

Exhibit 10.14

DESCRIPTION OF 2005 BONUS PROGRAM FOR EXECUTIVE OFFICERS

Under the Company’s bonus program, the annual bonus of the executive officers is determined by recommendation of the Compensation Committee, after reviewing recommendations of the Chairman and Chief Executive Officer, which is then submitted for approval by the full Board.  The amount of bonus that may be earned is based on a targeted percentage of the executive officer’s annual salary, subject to a maximum-targeted percentage. Subject to adjustment by the Board of Directors, the bonuses of the executive officers for 2005 are based 80% on achievement of the Company’s performance objectives as established by the Compensation Committee and 20% on achievement of the individual’s performance objectives. The Company’s overall performance objectives are measured by certain operational and financial objectives.  The operational objectives for the Company for 2005 consisted of targeted annual increases in reserves (weighted 40%) and production (weighted 30%), competitive finding and development costs (“F&D”) (weighted 15%), lease operating expense (“LOE”) (weighted 7.5%) and general and administrative costs (“G&A”) (weighted 7.5%), as compared with those projected in the Company’s annual budget for the applicable period. Both the LOE and G&A measures are calculated on the unit-of-production basis with targets set by the Compensation Committee. In addition, the F&D objective, weighted at 15%, is calculated as a three-year moving average using a unit-of-production basis, and is determined without including any F&D costs associated with acquisitions. This is the only category of the performance objectives where acquisitions are excluded. The financial goals for the Company for 2005 were: (1) to ensure that funds were available to execute the Company’s overall recommended case capital spending program as projected in its 2005 annual budget and plan (the “Recommended Case”) while maintaining a prudent financial structure with a debt-to-total capital ratio of less than 30%, subject to adjustment due to acquisitions; (2) to fund the Recommended Case, excluding acquisitions, from internal cash flow rather than taking on more debt; and (3) building pre-tax cash flow from our exploration and production activities to a level sufficient to provide the necessary funds to conduct a program that will provide consistent physical (reserve and production) and fiscal (cash flow and net income) growth for the Company.

Individual performance is assessed by a performance management process based on mutually defined expectations for each employee, including executive officers. The process includes individual appraisal components that are both objective and subjective. The objective components include quantifiable objectives and the subjective performance components include roles and accountabilities, performance attributes and behaviors. Individual performance of the executive officers, except the Chief Executive Officer, is first assessed by the Chief Executive Officer, who makes recommendations to the Compensation Committee for its consideration.  Bonus opportunities for 2005 for Mr. Long ranged from 0% to 80% of base salary, for Mr. Tugwell from 0% to 80% of base salary, and for Mr. Elias from 0% to 100% of his base salary subject to the achievement of specific objective and subjective performance criteria established mutually between the Compensation Committee and Mr. Elias on an annual basis. Bonus awards, if any, to be paid for 2005 performance are not determined as of the date of this Form 10-K and will be reported in the Proxy Statement for the 2006 Annual Meeting. Under the bonus program, the 2005 bonuses will be paid in cash. All bonuses are subject to the final approval of the Board of Directors.

EX-21.1

EXHIBIT 21.1

SUBSIDIARIES OF THE COMPANY

Edge Petroleum Exploration Company (a Delaware corporation)

Edge Petroleum Operating Company, Inc. (a Delaware corporation)

Miller Oil Corporation (a Michigan corporation)

Miller Exploration Company (a Delaware corporation)

Edge Petroleum Production Company (formerly Cinco Energy Corporation, a Delaware corporation)

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

Edge Petroleum Corporation

Houston, Texas

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-125677) and Form S-8 (No. 333-113619, No. 333-106484, No. 333-61890, No. 333-93209, and No. 333-22571) of Edge Petroleum Corporation (the “Company”)of our reports dated March 10, 2006, relating to the consolidated financial statements and to the effectiveness of the Company’s internal control over financial reporting, which appear in this Annual Report on Form 10-K.

/s/ BDO SEIDMAN, LLP

Houston, Texas

March 14, 2006

EX-23.2

EXHIBIT 23.2

March 14, 2006

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the incorporation by reference in the previously filed Registration Statements on Form S-8 No. 333-22571, No. 333-93209, No. 333-61890, No. 333-106484 and No. 333-113619 and Registration Statement on Form S-3 No. 333-125677, eachof Edge Petroleum Corporation (the “Company”), of our summary report dated March 3, 2006 included as Exhibit 99.1 to this Annual Report on Form 10-K in respect of our reserve report relating to the oil and gas reserves and revenues of certain interests of the Company as of December 31, 2005 and of the data extracted from such reports appearing in “Items 1 and 2. Business and Properties under the caption “Oil and Natural Gas Reserves” and in Note 20. Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities (unaudited) of the Company’s Consolidated Financial Statements for the year ended December 31, 2005, each contained in such Annual Report on Form 10-K. We hereby consent to all references to such reports and/or this firm in such Annual Report on Form 10-K and we hereby consent to all references to such reports and/or to this firm in each such Registration Statement, and further consent to our being named as an expert in each such Registration Statement and in each Prospectus to which any such Registration Statement relates.

BY:	/S/ RYDER SCOTT COMPANY, L.P.,
	PETROLEUM ENGINEERS
	RYDER SCOTT COMPANY, L.P.
	PETROLEUM ENGINEERS

EX-23.3

EXHIBIT 23.3

March 14,  2006

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the incorporation by reference in the previously filed Registration Statements on Form S-8 No. 333-22571, No. 333-93209, No. 333-61890, No. 333-106484 and No. 333-113619 and Registration Statement on Form S-3 No. 333-125677, eachof Edge Petroleum Corporation (the “Company”), of our summary report dated January 25, 2006 included as Exhibit 99.2 to this Annual Report on Form 10-K in respect of our reserve report relating to the oil and gas reserves and revenues of certain interests of the Company as of December 31, 2005 and of the data extracted from such reports appearing in “Items 1 and 2. Business and Properties under the caption “Oil and Natural Gas Reserves” and in Note 20. Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities (unaudited) of the Company’s Consolidated Financial Statements for the year ended December 31, 2005, each contained in such Annual Report on Form 10-K. We hereby consent to all references to such reports and/or this firm in such Annual Report on Form 10-K and we hereby consent to all references to such reports and/or to this firm in each such Registration Statement, and further consent to our being named as an expert in each such Registration Statement and in each Prospectus to which any such Registration Statement relates.

W.D. VON GONTEN & CO.
BY:	/S/ W. D. VON GONTEN, JR.
WILLIAM D. VON GONTEN, JR.
PRESIDENT

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

Principal Executive Officer

I, John W. Elias, certify that:

1.I have reviewed this annual report on Form 10-K of Edge Petroleum Corporation (the “registrant”).

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; and

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 14, 2006	/s/ John W. Elias
		John W. Elias
		President, Chief Executive Officer
		and Chairman of the Board

EX-31.2

EXHIBIT 31.2

Principal Financial Officer

I, Michael G. Long, certify that:

1.I have reviewed this annual report on Form 10-K of Edge Petroleum Corporation (the “registrant”).

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; and

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 14, 2006	/s/ Michael G. Long
		Michael G. Long
		Senior Vice President and Chief
		Financial and Accounting Officer

EX-32.1

EXHIBIT 32.1

Certification Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, John W. Elias, Chief Executive Officer of Edge Petroleum Corporation, a Delaware corporation (the “Company”), hereby certify, to my knowledge, that:

(1)the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:	March 14, 2006		/s/ John W. Elias
		Name:		John W. Elias
				Chief Executive Officer

EX-32.2

EXHIBIT 32.2

Certification Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, Michael G. Long, Chief Financial Officer of Edge Petroleum Corporation, Inc., a Delaware corporation (the “Company”), hereby certify, to my knowledge, that:

(1)the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:	March 14, 2006		/s/ Michael G. Long
		Name:		Michael G. Long
				Chief Financial and Accounting Officer

EX-99.1

Exhibit 99.1

March 3, 2006

Edge Petroleum Corporation

1301 Travis Street, Suite 2000

Houston, Texas 77002

Gentlemen:

At your request, we have prepared an estimate of the reserves, future production, and income attributable to certain leasehold and royalty interests of Edge Petroleum Corporation (Edge) as of December 31, 2005. The subject properties are located in the states of Alabama, Louisiana, Michigan, Mississippi, New Mexico, and Texas. The income data were estimated using the Securities and Exchange Commission (SEC) guidelines for future price and cost parameters.

The estimated reserves and future income amounts presented in this report are related to hydrocarbon prices. December 31, 2005 hydrocarbon prices were used in the preparation of this report as required by SEC guidelines; however, actual future prices may vary significantly from December 31, 2005 prices. Therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

Edge Petroleum Corporation

As of December 31, 2005

	Proved
	Developed						Total Proved
	Producing		Non-Producing		Undeveloped
Net Remaining Reserves
Oil/Condensate – Barrels	705,874		700,042		221,902		1,627,818
Plant Products – Barrels	768,620		362,998		101,962		1,233,580
Gas – MMCF	24,171		13,277		8,547		45,995
Income Data ($M)
Future Gross Revenue	$	270,560.6	$	165,776.7	$	91,627.8	$	527,965.1
Deductions	52,559.2		22,350.1		31,216.0		106,125.3
Future Net Income (FNI)	$	218,001.4	$	143,426.6	$	60,411.8	$	421,839.8
Discounted FNI @ 10%	$	164,589.8	$	71,142.5	$	40,626.5	$	276,358.8

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are sales gas expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

The future gross revenue is after the deduction of production taxes. The deductions are comprised of the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, and development costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. Gas reserves account for approximately 79 percent and liquid hydrocarbon reserves account for the remaining 21 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown on each estimated projection of future production and income presented in a later section of this report and in summary form below.

	Discounted Future Net Income ($M) As of December 31, 2005
Discount Rate Percent	Total Proved
12	$	259,861.5
15	$	239,111.0
20	$	212,161.2
25	$	191,675.6

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulation S-X Part 210.4-10 (a) as clarified by subsequent Commission Staff Accounting Bulletins. The definitions of proved reserves are included in the section entitled “Petroleum Reserves Definitions” which is attached with this report.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled, and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

The proved developed non-producing reserves included herein are comprised of shut-in and behind pipe categories. The various reserve status categories are defined in the section entitled “Petroleum Reserves Definitions” which is attached with this report.

Estimates of Reserves

In general, the reserves included herein were estimated by performance methods or the volumetric method; however, other methods were used in certain cases where characteristics of the data indicated such other methods were more appropriate in our opinion. The reserves estimated by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by the volumetric method in those cases where there

were inadequate historical performance data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.

Future Production Rates

Initial production rates are based on the current producing rates for those wells now on production. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations which are not currently producing. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Edge.

The future production rates from wells now on production may be more or less than estimated because of changes in market demand or allowables set by regulatory bodies. Wells or locations which are not currently producing may start producing earlier or later than anticipated in our estimates of their future production rates.

Hydrocarbon Prices

Edge furnished us with hydrocarbon prices in effect at December 31, 2005 and with its forecasts of future prices which take into account SEC and Financial Accounting Standards Board (FASB) rules, current market prices, contract prices, and fixed and determinable price escalations where applicable.

In accordance with FASB Statement No. 69, December 31, 2005 market prices were determined using the daily oil price or daily gas sales price (“spot price”) adjusted for oilfield or gas gathering hub and wellhead price differences (e.g. grade, transportation, gravity, sulfur and BS&W) as appropriate. Also in accordance with SEC and FASB specifications, changes in market prices subsequent to December 31, 2005 were not considered in this report.

For hydrocarbon products sold under contract, the contract price including fixed and determinable escalations, exclusive of inflation adjustments, was used until expiration of the contract. Upon contract expiration, the price was adjusted to the current market price for the area and held at this adjusted price to depletion of the reserves.

Costs

Operating costs for the leases and wells in this report are based on information provided by Edge and include only those costs directly applicable to the leases or wells. When applicable, the operating costs include a portion of general and administrative costs allocated directly to the leases and wells under terms of operating agreements. No deduction was made for indirect costs such as general administration and overhead expenses, loan repayments, interest expenses, and exploration and development prepayments that are not charged directly to the leases or wells.

Development costs were furnished to us by Edge and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The estimated net cost of

abandonment after salvage was included for properties where abandonment costs net of salvage are significant. At the request of Edge, their estimate of zero abandonment costs after salvage value for onshore properties was used in this report. Ryder Scott has not performed a detailed study of the abandonment costs nor the salvage value and makes no warranty for Edge’s estimate.

Current costs were held constant throughout the life of the properties.

General

While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may also increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

The estimates of reserves presented herein were based upon a detailed study of the properties in which Edge owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities which may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. Edge has informed us that they have furnished us all of the accounts, records, geological and engineering data, and reports and other data required for this investigation. The ownership interests, prices, and other factual data furnished by Edge were accepted without independent verification. The estimates presented in this report are based on data available through December 2005.

Edge has assured us of their intent and ability to proceed with the development activities included in this report, and that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future income for the subject properties.

This report was prepared for the exclusive use and sole benefit of Edge Petroleum Corporation and may not be put to other use without our prior written consent for such use. The data, work papers, and maps used in this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

/s/ MIKE F. STELL

Michael F. Stell, P.E.

Senior Vice President

EX-99.2

Exhibit 99.2

W.D. VON GOTNEN & CO

PETROLEUM ENGINEERING

808 Travis, Suite 812

Houston, TX 77002

(713) 224-6333 FAX (713) 224-6330

January 25, 2006

Mr. John Tugwell

Edge Petroleum Corporation

1301 Travis, Suite 2000

Houston, Texas 77002

Re:	Edge Petroleum Corporation
	Mestena Grande Properties
	“As of” January 1, 2006

Dear Mr. Tugwell:

At your request, we have prepared estimates of the future reserves and projected net revenues for the Mestena Grande Area property interests owned by Edge Petroleum Corporation (Edge), “As of” January 1, 2006. This report was prepared utilizing spot prices as posted on December 31, 2005, as per SEC guidelines. The subject properties are located in Jim Hogg and Brooks Counties, Texas.

Our conclusions, as January 1, 2006, are as follows:

	Proved - Net to Edge Petroleum Corporation
	Proved Developed						Proved
	Producing		Nonproducing		Behindpipe		Undeveloped		Total
Reserve Estimates
Oil/Cond., Mbbl	286.1		27.4		0.9		234.7		549.0
Gas, MMcf	19,861.6		1,684.1		72.2		14,677.1		36,295.0
Gas Equivalent, Mcfe	21,578.3		1,848.4		77.3		16,085.2		39,589.1
Revenues
Oil, $(8.3)%	17,015,170		1,628,019		50,522		13,956,484		32,650,193
Gas, $(91.7)%	197,469,734		16,616,023		643,625		145,123,609		359,853,000
Total, $	214,484,953		18,244,043		694,147		159,080,109		392,503,281
Expenditures
Ad Valorem Tax, $	5,116,507		423,074		16,089		3,688,845		9,244,518
Severance Tax, $	11,067,140		1,321,091		50,596		11,526,267		23,965,092
Direct Operating Expense, $	32,584,098		2,564,290		125,323		21,681,967		56,955,676
Total, $	48,767,746		4,308,455		192,007		36,897,082		90,165,281
Investments
Total, $	0		1,987,614		57,085		40,290,211		42,334,910
Estimated Future Net Revenues(FNR)
Undiscounted FNR	165,717,172		11,947,976		445,055		81,892,805		260,003,031
FNR Disc. @ 10%	121,322,055		8,566,185		208,530		48,827,492		178,924,234
Allocation Percentage by Classification
FNR Disc. @ 10%	67.8	%	4.8	%	0.1	%	27.3	%	100.0	%

Report Qualifications

Purpose of Report – The purpose of this report is to provide Edge with a projection of future reserves and revenues, which can be attributed to the Mestena Grande Area oil and gas properties owned by Edge.

Scope of Work – W.D. Von Gonten & Co. was engaged by Edge to estimate and project the future reserves associated with the various properties included in this report. Once the reserves were estimated, future revenue projections were made based on a SEC constant price deck as requested by Edge.

Reporting Requirements – Securities and Exchange Commission (SEC) Regulation S-K, Item 102 and Regulation S-X, Rule 4-10, and Financial Accounting Standards Board (FASB) Statement No. 69 require oil and gas reserve information to be reported by publicly held companies as supplemental financial data. These regulations and standards provide for estimates of Proved reserves and revenues discounted at 10% and based on unescalated prices and costs. Revenues based on escalated product prices may be reported in addition to the current pricing case. Probable reserves are prohibited from use for SEC reporting purposes and should be excluded from such filings.

The Society of Petroleum Engineers (SPE) requires Proved reserves to be economically recoverable with prices and costs in effect on the “as of” date of the report. In addition, the SPE has issued Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information, which sets requirements for the qualifications and independence of reserve estimators and auditors.

The estimated Proved reserves have been prepared in conformance with all SEC, SPE, and World Petroleum Congress (WPC) definitions and requirements.

Projections – The attached reserve and revenue projections are on a calendar year basis with the first time period being January 1, 2006 through December 31, 2006.

Reserve Estimates

Mesteña Grande Area – The Mesteña Grande Area is located in Jim Hogg County, Texas with production primarily from the Queen City Sand. Mesteña Inc. and Edge are the operators of the 62 producing wells in the area of which Edge owns an interest.

Edge and Mesteña drilled a total of 24 new Queen City Wells in 2005. At yearend, 21 of the 24 were producing. This increase in drilling activity has substantially increased the estimated recoverable reserves associated with the Queen City Reservoir. This property set exited 2004 with a total gross production rate of 19.0 MMcf/day. The current 2005 exit rate is +/- 30.0 MMcf/day.

Reserve estimates for the producing properties were based on a combination of 1) Extrapolation of monthly production histories, 2) Material Balance Calculations, 3) Volumetric Calculations, and 4) Analogy to offset production. Queen City wells decline in a hyperbolic nature as would be expected from a fractured tite gas reservoir. This hyperbolic trend has been observed in wells throughout the Queen City Trend, and a decline analogy has been utilized to aid in projecting remaining reserves. In all wells the future production performance was extrapolated from the daily production histories where both gas production and tubing pressures were analyzed.

All projected reserve estimates, for the wells producing from the Queen City Sand, were verified for “reasonableness” by overlaying the reserves onto a hydrocarbon pore volume map. W.D. Von Gonten & Co. has prepared this hydrocarbon pore volume map as part of an extensive field study that we have performed on the Queen City Formation in the Mesteña Grande Area.

Reserve estimates for the Proved Undeveloped locations were based on a combination of analogy, volumetrics, and material balance. Undeveloped locations were assigned in areas that are within the

seismic anomaly of “productive area” but outside of the drainage area of the current producing wells. Further, recent bottomhole pressure information was evaluated to verify that the additional reserves were present.

The Queen City is a package of tite gas depletion drive reservoirs. The study involved correlating more than 100 digital logs with both conventional and sidewall cores. This correlation allowed for a depiction of reservoir quality on a well-by-well basis. Analysis was also done on production tests before and after fracture jobs, and completion information in order to better understand the producing characteristics of the sands. Our conclusions indicate that there is a direct relationship between hydrocarbon pore volume and the productivity of the wells. Therefore, the proximity of individual wells to areas of high hydrocarbon pore volume correlates to the ultimate reserves assigned to each well in the Queen City Sand.

Reserves and schedules of production included in this report are only estimates. The amount of available data, reservoir and geological complexity, reservoir drive mechanism, and mechanical aspects can have a material effect on the accuracy of these reserve estimates.

Product Prices

The estimated revenues shown herein were based on the effective NYMEX spot prices on December 31, 2005 of $61.04 per barrel of oil and $10.05 per MMBtu of gas.

Oil pricing differentials were applied on an individual property basis to reflect actual prices received at the wellhead versus the NYMEX spot price. These differentials were calculated from comparing the South Texas Light Posting plus the P+ bonus with the NYMEX spot price. Pricing differentials account for transportation and processing costs, geographical differentials, quality adjustments, and any marketing bonus or deduction.

Gas prices have been adjusted according to the purchase contracts in place for the specific gas stream. The differential applied to each well from the NYMEX spot price was estimated by comparing the Houston Ship Channel daily and monthly indexes to the equivalent Henry Hub Index and accounting for the 2% transportation deduction. Quality adjustments have been applied based on actual BTU factors for each well. A shrinkage factor has been applied based on production volumes versus actual sales volumes, this shrinkage accounts for any line loss or fuel usage before the actual sales point.

Gas transportation and compression fees were included as a deduction from the gas price and assigned on a per Mcf basis based on contractual agreements.

Where no data was available, estimated differentials, BTU’s, and shrinkages were assigned based on analogy to pricing differentials utilized in similar producing regions.

All prices have been held constant throughout the life of the properties.

Operating and Capital Costs

The monthly expense necessary to operate each well was estimated based on the average of the last 12 month historical Joint Interest Billing Statements as supplied by Edge. These statements date from October 2004 through September 2005.

Capital costs necessary to perform drilling, workover and/or remedial operations were supplied by Edge in the form of detailed AFE’s.

All operating and capital costs have been held constant throughout the life of the properties.

Other Considerations

Abandonment Costs – The cost necessary to abandon the properties were assigned an expense of zero due to the credit of the salvage value of the surface and subsurface equipment. This was verified with the abandonment of the Libre Nos. 3 & 5 in 2004. Both wells were abandoned and the credit from the equipment exceeded the costs.

Additional Costs – Costs were not deducted for depletion, depreciation and/or amortization (a non-cash item), or federal income tax.

Data Sources – Data furnished by Edge included basic well information, operating cost, ownership, pricing, and production information on certain leases. The remaining production histories were taken from IHS Energy data archives.

Context – We specifically advise that any particular reserve estimate for a specific property not be used out of context with the overall report. The revenues and present worth of future net revenues are not represented to be market value either for individual properties or on a total property basis.

We have not inspected the properties included in this report, nor have we conducted independent well tests. W.D. Von Gonten & Co. and our employees have no direct ownership in any of the properties included in this report. Our fees are based on hourly expense and are not related to the reserve and revenue estimates produced in this report.

Thank you for the opportunity to work with Edge on this project.

Respectfully submitted,

/s/ William D. Von Gonten, Jr.

William D. Von Gonten, Jr., P.E.

TX# 73244