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

FORM 10-K

(MARK ONE)ý

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2008ORo

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period
from                        to


Commission file number: 0-22149

EDGE PETROLEUM CORPORATION(Exact Name of Registrant as Specified in Its Charter)

Delaware(State or Other Jurisdiction of
Incorporation or Organization)

76-0511037(I.R.S. Employer
Identification No.)1301 Travis, Suite 2000 Houston, Texas(Address of Principal Executive Offices)

77002(Zip Code)


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



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

Title of Each Class

Name of Each Exchange on Which RegisteredCommon Stock, Par Value $0.01 Per Share

NASDAQ5.75% Series A Cumulative Convertible Perpetual

NASDAQPreferred Stock, Par Value $0.01 Per Share


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



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. ý

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

o Large accelerated filer

ý Accelerated Filer

o Non-accelerated filer (Do not check if a smaller reporting company)

o Smaller reporting company


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

As of June 30, 2008, the aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant
was $144.1 million (based on a value of $5.39 per share, the closing price of the Common Stock as quoted by The NASDAQ Global Select Market on such date).

As
of March 12, 2009, 28,836,927 shares of Common Stock, par value $0.01 per share, were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the registrant's 2009 Annual Meeting of Shareholders, to be filed pursuant to Regulation 14A under the
Securities Exchange Act of 1934, are incorporated by reference into Part III of this report.



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TABLE OF CONTENTS



PagePART IITEMS 1 AND 2.

BUSINESS AND PROPERTIES


4ITEM 1A.

RISK FACTORS


25ITEM 1B.

UNRESOLVED STAFF COMMENTS


39ITEM 3.

LEGAL PROCEEDINGS


42ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS


43PART IIITEM 5.

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


46ITEM 6.

SELECTED FINANCIAL DATA


48ITEM 7.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS


50ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


83ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


84ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES


85ITEM 9A.

CONTROLS AND PROCEDURES


85ITEM 9B.

OTHER INFORMATION


87PART IIIITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE


88ITEM 11.

EXECUTIVE COMPENSATION


88ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS


88ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE


88ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES


88PART IVITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES


89


2

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EDGE PETROLEUM CORPORATION

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

FORWARD LOOKING INFORMATION

The information contained in this Annual Report on Form 10-K includes certain forward-looking statements. The words
"may," "will," "expect," "anticipate," "believe," "continue," "estimate," "project," "intend," and similar expressions used in this Form 10-K are intended to identify
forward-looking statements within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. You
should not place undue reliance on these forward-
looking statements, which speak only as of the date made. We undertake no obligation to publicly release the result of any revision of these forward-looking statements to reflect events or
circumstances after the date they are made or to reflect the occurrence of unanticipated events. You should also know that such statements are not guarantees of future performance and are subject to
risks, uncertainties and assumptions. Should any of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may differ materially from those included
within the forward-looking statements. For a discussion of the risks which, among others, may affect our financial condition and results of operations please see our risk factors set forth under ITEM 1A. "RISK
FACTORS"of this Annual Report.

AVAILABLE INFORMATION

Our website address iswww.edgepet.com. We make our website content available for
information purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. We make available on this website under
"Investor RelationsSEC Filings," free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on
Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. The SEC also
maintains a website atwww.sec.govthat contains reports, proxy statements and other information regarding SEC registrants, including us.

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PART I

ITEMS 1 AND 2.    BUSINESS AND PROPERTIES

Overview & History

Edge Petroleum Corporation is an independent oil and natural gas company engaged in the exploration, development, acquisition and
production of crude oil and natural gas properties from select onshore basins in the United States. Edge was founded in 1983 as a private company and went public in 1997. We have evolved over time
from a prospect generation organization focused on high-risk, high-reward exploration projects to a team-driven organization focused on a balanced program of
exploration, exploitation, development and acquisition of oil and natural gas properties. In late 2007, in an attempt to enhance shareholder value we began to assess our strategic alternatives (more
fully discussed below) and have subsequently expanded this process to include a further evaluation of both our financial and strategic alternatives in late 2008 and continuing into 2009. Our current
primary focus is on capital preservation and resolving the uncertainty and challenges we face.

Recent Developments

At year-end 2008, our net proved reserves were 124.1 Bcfe, comprised of 89.6 billion cubic feet of natural
gas, 3.5 million barrels of natural gas liquids and 2.3 million barrels of crude oil and condensate. Natural gas and natural gas liquids accounted for approximately 89% of those proved
reserves. Approximately 79% of our total proved reserves were developed as of year-end 2008 and they were all located onshore, in the United States. Our reduced drilling program resulted
in 25 gross (8.74 net) apparent successes out of 27 gross (9.95 net) wells drilled in 2008. During 2008, we focused a great deal of our efforts on our financial and strategic alternatives process (see
below). In January 2009, the lenders ("Lenders") to our Fourth Amended and Restated Credit Agreement (as amended, the "Revolving Facility") completed their borrowing base redetermination, which
resulted in a reduction of our borrowing base to $125 million, thereby eliminating availability for additional borrowing for the near future and creating a substantial borrowing base deficiency
of $114 million (the "Deficiency"), which is described below and in Note 11 to our consolidated financial statements. This Deficiency was largely the result of lower commodity prices and
increased costs which impacted the reserve calculation used to redetermine our borrowing base along with our inability to replace and increase our reserves over the last year.

Financial and Strategic Alternatives ProcessIn late 2007, we announced the hiring of a financial advisor to assist our Board of Directors with an
assessment of strategic alternatives. On February 7, 2008, we provided an update on the strategic alternative process and publicly announced that we would implement a process to explore a
merger or sale of the Company. As a result of the strategic alternatives process, on July 15, 2008, we and Chaparral Energy, Inc. ("Chaparral"), a privately
held company, announced that we had entered into a definitive merger agreement that provided for Chaparral to acquire Edge in an all-stock transaction. To provide additional funding for
the transaction, Chaparral expected to sell 1.5 million shares of its Series B convertible preferred stock, par value $0.01 per share for $150 million in a private sale to
Magnetar Financial LLC, on behalf of itself and one or more of its affiliates and assigns (collectively, "Magnetar").

The
credit crisis and related turmoil in the global financial system and economic recession in the U.S. during the fourth quarter of 2008, along with declines in commodity prices and our
stock prices, created a challenging environment for the successful completion of our proposed merger with Chaparral. On December 17, 2008, we announced the termination of the Chaparral merger
agreement after both we and Chaparral determined it was highly unlikely that the conditions to the closing of the proposed merger would be satisfied or that Chaparral would be able to obtain
sufficient debt and equity financing to allow them to complete the proposed merger and operate as a combined company, particularly in light of the challenging environment in the financial markets and
the energy industry. As

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a
result, after consultation with our legal and financial advisors, our Board of Directors approved a merger termination agreement with Chaparral and a termination and settlement agreement among us,
Chaparral and Magnetar. Pursuant to the termination agreements, Magnetar reimbursed Chaparral $5.0 million for certain expenses, of which $1.5 million was paid to us at Chaparral's
direction, of which we paid $0.3 million to our then-financial advisor, Merrill Lynch.

During
January 2009, we announced that the Lenders to our Revolving Facility had completed their borrowing base redetermination and reduced our borrowing base to $125 million,
resulting in the Deficiency. Pursuant to the terms of the Revolving Facility, we elected to prepay the Deficiency in six equal monthly installments, with the first $19 million installment being
due on February 9, 2009. On February 9, 2009, we entered into a Consent and Agreement (the "February Consent") among us and the Lenders under the Revolving Facility deferring the payment
date of the first $19 million installment until March 10, 2009, and extending the due date for each subsequent installment by one month with the last of the six installment payments to
be due on August 10, 2009. In connection with the February Consent, we agreed to prepay $5.0 million of our outstanding advances under the Revolving Facility, in two equal installments.
The first $2.5 million prepayment was paid on February 9, 2009 and the second $2.5 million prepayment was paid on February 23, 2009, with each of the prepayments to be
applied on a pro rata basis to reduce the remaining six $19 million deficiency payments. On March 10, 2009, we entered into a Consent and Agreement (the "March Consent") with the Lenders
under the Revolving Facility, which provided, among other things, for the extension of the due date for the first installment to repay the Deficiency from March 10, 2009 to March 17,
2009. Notwithstanding such extension, we agreed with the Lenders that each of the other five equal installment payments required to eliminate the Deficiency would be due and payable as provided for in
the February Consent.

On
March 16, 2009, we entered into Consent and Amendment No. 4 to our Revolving Facility (the "Amended Consent") which provides, among other things, (1) that we will
make a $25 million payment on May 31, 2009 with all remaining principal, fees and interest amounts under our Revolving Facility to be due and payable on June 30, 2009,
(2) that it will be an event of default (i) if we fail to have executed and delivered on or before May 15, 2009 at least one of the following (a) a commitment letter from a
lender or group of lenders reasonably satisfactory to our Lenders providing for the provision by such lender or group of lenders of a credit facility in an amount sufficient to repay all of our
obligations under the Revolving Facility on or before June 30, 2009, (b) a merger agreement or similar agreement involving us as part of a transaction that results in the repayment of
our obligations under the Revolving Facility on or before June 30, 2009, and (c) a purchase and sale agreement with a buyer or group of buyers reasonably acceptable to our Lenders
providing for a sale transaction by us that results in the repayment of all of our obligations under the Revolving Facility on or before June 30, 2009, or (ii) if we are in default under
or our hedging arrangements have been terminated or cease to be effective without the prior written consent of our Lenders, (3) that our advances under the Revolving Facility will bear interest
at a rate equal to the greater of (a) the reference rate publicly announced by Union Bank of California, N.A. for such day, (b) the Federal Funds Rate in effect on such day plus
0.50% and (c) a rate determined by the Administrative Agent to be the Daily One-Month LIBOR (as defined in the Revolving Facility), in each case plus 2.5% or, during the
continuation of an event of default, plus 4.5% (resulting in an effective interest rate of approximately 5.75% as of March 16, 2009), (4) for limitations on the making of capital
expenditures and certain investments, and (5) for the elimination of the current ratio, leverage ratio and interest coverage ratio covenant requirements. The Amended Consent also eliminates the
six $19 million deficiency payments which were contemplated by the February Consent and the March Consent. To comply with the terms of the Amended Consent, we anticipate that we will need to
(i) sell select individual assets prior to May 31, 2009 to enable us to make the $25 million payment which is due on May 31, 2009, and/or (ii) negotiate a commitment
letter with a new lender or group of lenders prior to May 15, 2009 in an amount sufficient to repay all of our obligations under the Revolving Facility on or before June 30, 2009, and/or
(iii) have negotiated the sale, merger or other business combination involving us which

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results
in the repayment of all of our obligations under the Revolving Facility prior to May 15, 2009 and to have closed such transaction on or before June 30, 2009. The Amended Consent
limits the making of capital expenditures and we anticipate a severe curtailment of our drilling plans and other capital expenditures in 2009.

If
we breach any of the provisions of the Amended Consent or the Revolving Facility, our Lenders will be entitled to declare an event of default, at which point the entire unpaid
principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, would become immediately due and payable. In any event, the entire unpaid
principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, will be payable on June 30, 2009 unless earlier paid or a further
extension with respect to payment is negotiated with our Lenders. Our Lenders may take action to enforce their rights with respect to the outstanding obligations under the Revolving Facility. Because
substantially all of our assets are pledged as collateral under the Revolving Facility, if our Lenders declare an event of default, they would be entitled to foreclose on and take possession of our
assets. In such an event, we may be forced to liquidate or to otherwise seek protection under Chapter 11 of the U.S. Bankruptcy Code. These matters, as well as the other risk factors related to
our liquidity and financial position raise substantial doubt as to our ability to continue as a going concern. SeeITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONSLIQUIDITY AND CAPITAL RESOURCESREVOLVING FACILITY."With respect to our compliance with the
Amended Consent, there can be no assurance that we will be able to further negotiate the terms of the Amended Consent or negotiate a further restructuring of the related indebtedness or that we will
be able to make any required payments when they become due. Moreover, there can be no assurance that we will be successful in our efforts to comply with the terms of the Amended Consent, including our
ongoing efforts to evaluate and assess our various financial and strategic alternatives (which may include the sale of some or all of our assets, a merger or other business combination involving the
Company, or the restructuring or recapitalization of the Company). If such efforts are not successful, we may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

Going ConcernIn addition to the Deficiency under our Revolving Facility, the capital expenditures required to maintain and/or grow production and
reserves are substantial. Our stock price has significantly declined over the past year which makes it more difficult to obtain equity financing on acceptable terms to address our liquidity issues. In
addition, we are reporting negative working capital at December 31, 2008 and a third consecutive year of net losses for the year ended December 31, 2008, which is largely the result of
impairments of our oil and natural gas properties. Therefore, there is substantial doubt as to our ability to continue as a going concern for a period longer than the current fiscal year. Our ability
to continue as a going concern is dependent upon the success of our financial and strategic alternatives process, which may include the sale of some or all of our assets, a merger or other business
combination involving the Company or the restructuring or recapitalization of the Company. Until the possible completion of the financial and strategic alternatives process, our future remains
uncertain and there can be no assurance that our efforts in this regard will be successful.

Our
consolidated financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which implies we will continue to meet
our obligations and continue our operations for the next twelve months. Realization values may be substantially different from carrying values as shown, and our financial statements do not include any
adjustments relating to the recoverability or classification of recorded asset amounts or the amount and classification of liabilities that might be necessary as a result of this uncertainty. Our
independent auditors have included an explanatory paragraph in their report on our consolidated financial statements that raises substantial doubt about our ability to continue as a going concern. See ITEM 8. "FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATAReport of the Independent Registered Accounting Firm."

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Strategy

In connection with our ongoing financial and strategic alternatives process and due to our liquidity issues resulting from the
Deficiency and the related Amended Consent, we will be operating with a reduced capital spending program in 2009 as we continue to pursue the sale of some or all of our assets, a merger or other
business combination involving the Company or the restructuring or recapitalization of the Company. Our strategy is currently to continue under a severely limited capital and operating budget, thereby
reducing our normal exploration and development activities as we seek to preserve liquidity and resolve the uncertainty and challenges that we face and pursue various financial and strategic
alternatives. We expect to drill three to four wells (0.6 to 1.0, net) during 2009, in south Texas, southeast New Mexico, and in the Arkansas Fayetteville Shale Play, complemented by a recompletion
program in south Texas and selected expenditures for land and seismic. We anticipate these activities will result in total capital spending in the range of $15 to $20 million for 2009.

Employees

As of March 11, 2009, we had 57 full-time and 2 part-time employees. We believe that we have good
relationships with our employees. None of our employees is covered by a collective-bargaining agreement. In addition, we utilize the services of independent consultants and contractors to perform
various professional services, particularly in the areas of engineering, construction, design, well-site surveillance, permitting and environmental assessment. Field and
on-site production operation services, such as pumping, maintenance, dispatching, inspection and testing, are generally provided by independent contractors.

Offices

We lease executive and corporate office space located at 1301 Travis Street, Suite 2000, Houston, Texas, 77002.

Oil and Natural Gas Reserves

The Company's reserves decreased in 2008 due to lower commodity prices, production, property sales and revisions to previous estimates.
We were unable to replace the production we generated due to our reduced capital spending program and higher drilling and operating costs. However, the decrease was partially offset by extensions and
discoveries that resulted from the drilling of 25 gross (8.74 net) apparent successes, recompletion of one well, and the addition of one proved undeveloped ("PUD") location. Revisions to previous
estimates during 2008 were primarily due to (1) commodity pricing that was significantly lower than year-end 2007, causing a number of PUD locations to be uneconomic and shortening
the economic life of many other properties, (2) results of actual drilling and recompletion operations and updated technical analysis, (3) updates to shrink and differential factors and
(4) updated performance (both positive and negative) on existing producing wells. The Company's net ownership in estimated quantities of proved oil and natural gas reserves and the present
value of estimated future net cash flows related to such reserves, all of which are located in the continental United States, are summarized below.

We
engaged Ryder Scott Company, L.P. ("Ryder Scott") and W. D. Von Gonten & Co. ("WDVG") to estimate our net proved reserves, projected future
production, estimated future net revenue attributable to our proved reserves, and the present value of such estimated future net revenue as of December 31, 2008. Ryder Scott's 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 15 years and WDVG has independently evaluated the reserves we acquired late in 2004 for the past seven years. In estimating the reserve quantities that are economically recoverable, Ryder
Scott and WDVG used oil and natural

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gas
prices in effect at December 31, 2008 and estimated development and production costs that were in effect during December 2008 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, 2008, see the summaries of the reserve reports of Ryder Scott and WDVG included as exhibits to this Form 10-K (respectively, the "Ryder Scott Report" and the
"WDVG Report"). In accordance with Statement of Financial Accounting Standards ("SFAS") No. 69,Disclosures About Oil and Natural Gas Producing
Activities,the present value of estimated future net revenues after income taxes was prepared using constant prices as of the calculation date, discounted at 10% per annum,
but is not intended to represent the current market value of the estimated oil and natural gas reserves we owned. For further information concerning the present value of future net revenue from our
proved reserves, see Note 23 to our consolidated financial statements. See alsoITEM 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. The following table reflects a summary of our proved reserve volumes and a
reconciliation between estimated future net revenue, before income taxes, attributable to estimated proved reserves, discounted at 10% per annum (the "PV-10 Value") and the standardized
measure of discounted future net cash flows.

Proved Reserves as of December 31, 2008Developed(1)

Undeveloped(2)

TotalOil and condensate (MBbls)


1,971


302


2,273Natural gas liquids (MBbls)


2,833


646


3,479Natural gas (MMcf)


68,955


20,666


89,621Total MMcfe


97,783


26,349


124,132In thousands:Estimated future net revenue before income taxes

$
365,177

$
47,814

$
412,991PV10 Value(3)

$
255,238

$
21,967

$
277,205Future income taxes (discounted 10% per annum)(4)








Standardized measure of discounted future net cash flows

$
255,238

$
21,967

$
277,205


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The
reserve data set forth herein represents estimates only. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be
measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result,
estimates made by different 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, 2008, 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, 2008. In recent years, oil and natural gas commodity prices have generally trended upwards in response to robust demand and constrained supplies, with oil
and natural gas prices peaking at more than $140.00 per barrel and $13.00 per Mcf, respectively, in July 2008. In the second half of 2008, a world-wide economic recession and oversupply of
natural gas in North America led to an unprecedented decline in oil and natural gas prices, with oil prices falling by more than $100.00 per barrel and natural gas prices falling more than $8.00 per
Mcf from their peaks in July 2008. There can be no assurance that all of the proved reserves will be produced and sold within the periods indicated, that the assumed prices will actually be realized
for such production or that existing contracts will be honored or judicially enforced. Decreases in the assumed commodity prices result in decreases in estimated future net revenue as well as in
estimated reserves.

Oil and Natural Gas Reserve Replacement

Finding and developing sufficient amounts of natural gas and crude oil reserves at economical costs are critical to our
long-term success. Our business, as with other extractive businesses, is a depleting one in which each gas equivalent unit produced must be replaced or our asset base and ability to
generate revenues in the future will shrink. This was a factor in our 2008 results, which reflected a 24% lower proved reserve base at year-end. We were unable to replace the production we
generated due to our reduced capital spending program and higher drilling and operating costs. This will continue to be a factor in 2009 as we operate under a severely limited capital and operating
budget. 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

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production
volumes and grow our reserves, thereby providing some information on the sources of future production and income. We believe that reserve replacement is relevant and useful information that
is commonly used by analysts, investors and other interested parties in the oil and gas industry as a means of evaluating the operational performance and to a greater extent the prospects of entities
engaged in the production and sale of depleting natural resources. These measures are often used as a metric to evaluate an entity's historical track record of replacing the reserves that it has
produced. The reserve replacement ratio is calculated by dividing the sum of reserve additions from all sources (revisions, acquisitions, extensions and discoveries) by the actual production for the
corresponding period. Additions to our reserves are proven developed and proven undeveloped reserves. Our severely limited drilling program will restrict our ability to add to our reserve base. See ITEM 1A. "RISK
FACTORS". The values for these reserve additions and production are derived directly from the proved reserves table in
Note 23 to our consolidated financial statements. Accordingly, we do not use unproved reserve quantities. The reserve replacement ratio is a statistical indicator that has limitations. As an
annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also
limited for the same reasons. In addition, since the ratio does not consider the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. The ratio does
not distinguish between changes in reserve quantities that are developed and those that will require additional time and funding to develop. In that regard, the percentage of reserves that were
developed was 79%, 77%, and 77% for the years ended December 31, 2008, 2007 and 2006, respectively. Set forth below is our reserve replacement ratio for the periods indicated.

For the Year Ended December 31,Three Year Average2008(1)

2007

2006Reserve Replacement Ratio


(96
)%

362
%

97
%

150
%


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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 31,2008

2007

2006Production:Natural gas (MMcf)


12,059


17,536


13,850Natural gas liquids (MBbls)


559


637


222Oil and condensate (MBbls)


294


460


345Natural gas equivalent (MMcfe)


17,176


24,118


17,251Average sales pricebefore derivatives:Natural gas ($ per Mcf)

$
8.51

$
6.66

$
6.68Natural gas liquids ($ per Bbl)


48.83


40.00


25.52Oil and condensate ($ per Bbl)


101.66


70.86


63.10Natural gas equivalent ($ per Mcfe)


9.30


7.25


6.96Average sales priceafter derivatives:Natural gas ($ per Mcf)

$
8.62

$
6.80

$
7.36Natural gas liquids ($ per Bbl)


48.83


40.00


25.52Oil and condensate ($ per Bbl)


93.86


35.21


64.10Natural gas equivalent ($ per Mcfe)


9.24


6.67


7.52Average oil and natural gas operating expenses ($ per Mcfe)(1)

$
0.98

$
0.71

$
0.53Average production and ad valorem taxes ($ per Mcfe)

$
0.56

$
0.54

$
0.53


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Exploration, Development and Acquisition Capital Expenditures

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

Year Ended December 31,2008

2007

2006(in thousands)Acquisition costs:Unproved properties

$
12,752

$
64,483

$
21,661Proved properties





336,022


36,573Exploration costs


5,663


41,240


17,898Development costs(1)


41,430


74,920


65,140Total costs incurred

$
59,755

$
516,665

$
141,272


---

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.

11

---



Table of Contents

Drilling Activity

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

Year Ended December 31,2008

2007

2006Gross

Net

Gross

Net

Gross

NetExploratory:Productive


6


1.52


6


3.01


13


5.12Non-productive








2


1.63


5


2.66Total


6


1.52


8


4.64


18


7.78Development:Productive


19


7.22


40


21.53


30


18.28Non-productive


2


1.21


2


1.15


4


2.87Total


21


8.43


42


22.68


34


21.15Total


27


9.95


50


27.32


52


28.93Success Ratio


93
%

88
%

92
%

90
%

83
%

81
%


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, 2008. 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.

Company-Operated

Non-Operated

TotalGross

Net

Gross

Net

Gross

NetOil


38


21.76


39


5.72


77


27.48Natural gas


254


175.53


179


72.22


433


247.75Total


292


197.29


218


77.94


510


275.23


Acreage Data

The following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31,
2008. Developed acres refer to acreage within producing units and undeveloped acres refer to acreage that has not been placed in producing units. In the table, "Gross"

12

---



Table of Contents

refers
to the total acres in which we have an interest and "Net" refers to gross acres multiplied by our interest therein.

Developed Acres

Undeveloped Acres

TotalGross

Net

Gross

Net

Gross

NetTexasVicksburg


7,930


5,222


22,694


2,375


30,624


7,597TexasQueen City


39,057


18,194


1,545


420


40,602


18,614TexasDeep Frio


3,590


3,456


12,693


10,323


16,283


13,779TexasOther


6,924


2,939


15,864


4,335


22,788


7,274Southeast New Mexico


7,571


2,436


92,266


18,565


99,837


21,001Mississippi Interior Salt Basin


6,632


3,616


13,190


7,232


19,822


10,848South Louisiana


1,583


463








1,583


463Arkansas (Fayetteville Shale)


1,478


1,253


4,183


3,548


5,661


4,801Alabama


750


46








750


46Michigan


160


160


498


498


658


658Mississippi/Alabama (Floyd Shale)








26,273


21,448


26,273


21,448Montana








880


334


880


334Total


75,675


37,785


190,086


69,078


265,761


106,863


Leases
covering approximately 33,344 gross (12,904 net), 47,359 gross (31,216 net) and 16,131 gross (12,556 net) undeveloped acres are scheduled to expire in 2009, 2010 and 2011,
respectively. In general, our leases will continue past their primary terms if oil and natural gas production in commercial quantities is being produced from a well on such lease or other drilling or
reworking operations are being continuously prosecuted.

The
table above does not include 14,513 gross (9,977 net) undeveloped acres in Texas for which we have the option to acquire leases based upon a commitment of continuous drilling. We
estimate that these options to acquire leased acreage will expire in 2009 and 2010, based on our current well and 3-D seismic acquisition schedule and our severely limited drilling
program.

13

---



Table of Contents

Core Areas of Operation

As of December 31, 2008, 83% of our proved reserves were in Texas, 6% in New Mexico, 6% in Mississippi, and 5% in Arkansas,
south Louisiana, Michigan, and Alabama. In south Texas, our exploration and production activities are concentrated in three primary plays: Vicksburg, Queen City and Deep Frio trends. Our principal
properties are located in the following areas of the United States:

GRAPHIC

The
table below sets forth the gross and net number of our gas, oil and service wells in each of our core areas of operation as of December 31, 2008. Net wells are calculated
based on our working or net revenue interest in each of the properties we own.

Gas Wells

Oil Wells

Service Wells(1)Gross

Net

Gross

Net

Gross

NetTexasVicksburg


152


57.81


6


1.90


3


1.12TexasQueen City


88


60.05








1


0.30TexasDeep Frio


43


40.64


6


5.98


1


1.00TexasOther


105


69.74


3


0.84


2


1.25Southeast New Mexico


18


6.65


45


15.59


2


0.93Mississippi Interior Salt Basin


9


5.44


12


2.95





South Louisiana


6


1.38








3


0.41Arkansas


11


5.04











Michigan


1


1.00











All others








5


0.22


2


0.18Total


433


247.75


77


27.48


14


5.19


---

14

---



Table of Contents

We
conduct our operations primarily along the onshore United States Gulf Coast, with our primary emphasis in south Texas, southeast New Mexico, Mississippi, Arkansas and Louisiana. Our
resources and assets are managed and our results reported as one operating segment. The following table sets out a brief comparative summary of certain key 2008 data for each area.

Production
MMcfe

Percentage
of Total
Production

Production
Revenue
(in thousands)

Estimated
Proved
Reserves
MMcfe

Percentage
of Total
Estimated
Proved
Reserves

Gross
New
Wells
Drilled

Gross
New
Productive
Wells
DrilledState / Trend:TexasVicksburg


6,035


35
%
$
56,785


54,796


44
%

15


14TexasQueen City


3,426


20
%

30,442


12,032


10
%




TexasDeep Frio


2,207


13
%

19,045


10,209


8
%

1


TexasOther


3,064


18
%

27,252


25,927


21
%




Total Texas


14,732


86
%

133,524


102,964


83
%

16


14Southeast New Mexico


1,455


8
%

14,269


6,984


6
%

10


10Mississippi Interior Salt Basin


768


4
%

9,297


7,643


6
%




South Louisiana


64


1
%

951


6,370


5
%




Arkansas


58


*


402


119


*


1


1Michigan


91


1
%

947


47


*





All Others


8


*


364


5


*





Total


17,176


100
%
$
159,754


124,132


100
%

27


25


---

Due
to the ongoing financial and strategic alternatives process and our liquidity issues resulting from the Deficiency under our Revolving Facility and the related Amended Consent, our
planned activities in all of our areas of operation will be severely limited in 2009.

South & Southeast Texas

As of December 31, 2008, we owned an interest in 110,297 gross (47,264 net) acres in Texas. Our areas of focus in this region
are predominantly in the Vicksburg, Queen City and Deep Frio producing trends. As of December 31, 2008, we operated approximately 248 gross wells, which along with our 162 gross
non-operated wells, accounted for approximately 86% of our total net production in 2008. We drilled 16 gross wells during 2008 in Texas, of which 14 gross wells were apparent successes and
all of which were in the Vicksburg project area. The majority of our 2008 asset divestitures were properties located in Texas.

Southeast New Mexico

As of December 31, 2008, we owned an interest in 99,837 gross (21,001 net) acres in southeast New Mexico that we earned through
a drilling obligation we fulfilled during 2004 and 2005 and through subsequent purchases. The primary objectives in this area are shallow oil in the Yeso, San Andres, Queen and Grayburg formations,
and natural gas in the Atoka and Morrow formations. Additional objectives include the Strawn, Cisco, Wolfcamp and Devonian formations. In 2008, we participated in the drilling of 10 gross (2.3 net)
wells, of which all were apparently successful. As of December 31, 2008, we operated 34 gross wells in this area. Production from wells in the southeast New Mexico area represented
approximately 8% of our total net production in 2008.

15

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Table of Contents

Mississippi Interior Salt Basin

As of December 31, 2008, we owned an interest in 19,822 gross (10,848 net) acres in the Mississippi Interior Salt Basin area and
26,273 gross (21,448 net) undeveloped acres in the Floyd Shale play. We acquired reserves and production in the Mississippi Interior Salt Basin in south central Mississippi as part of the 2003 merger
with Miller Exploration Company ("Miller"). The primary producing horizons in the Mississippi Interior Salt Basin around the Miller properties include the Hosston, Sligo, Rodessa and James Lime
sections. As of December 31, 2008, we operated 10 gross wells in this area. Production from wells in the Mississippi Interior Salt Basin accounted for approximately 4% of our total net
production in 2008. We did not drill any wells in Mississippi in 2008. A portion of our 2008 asset divestitures included our Tallahalla Creek field in Mississippi.

South Louisiana

As of December 31, 2008, we owned an interest in 1,583 gross (463 net) acres in south Louisiana primarily located in Acadia and
Lafayette Parishes. As of December 31, 2008,
we had an interest in six gross wells, none of which we operate. Production from wells in south Louisiana represented approximately 1% of our total net production in 2008. We did not drill any wells
in south Louisiana in 2008.

Arkansas

As of December 31, 2008, we owned an interest in 5,661 gross (4,801 net) undeveloped acres in the Fayetteville Shale play in
south central Arkansas. In 2008, we drilled one gross (0.04 net) apparently successful well. Five wells in Arkansas had operations temporarily suspended at year-end 2007 because fracture
stimulation during the completion of our initial wells caused communication with an underlying water bearing zone. We are currently seeking approval to convert one of our existing shut-in
wells to a water disposal well. If successful, we plan to return three currently shut-in wells to production and re-inject the produced water from these wells into the water
disposal system. Much of the planned 2008 wells have been deferred. Production from wells in the Arkansas area represented less than 1% of our total net production in 2008.

Michigan

As of December 31, 2008, we owned an interest in 658 gross (658 net) acres in Michigan. We acquired acreage and one producing
well in south central Michigan as part of the 2003 merger with Miller. We operate this well which produces from the Trenton/Black River formation at approximately 3,000 feet and this well accounted
for approximately 1% of our total net production in 2008. We did not drill any wells in Michigan in 2008.

Title to Properties

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

We
have granted mortgage liens on substantially all of our oil and natural gas properties in favor of Union Bank of California, as agent, to secure our Revolving Facility. These
mortgages and the Revolving Facility contain substantial restrictions and operating covenants that are customarily found in

16

---



Table of Contents

loan
agreements of this type. SeeITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONSLIQUIDITY AND CAPITAL RESOURCESREVOLVING FACILITY"and Note 11 to our consolidated
financial statements.

Marketing

Our production is marketed to third parties consistent with industry practices. We market our own production where feasible and we also
engage third-party marketing agents. We use third-party agents to market our residue gas in interstate pipelines. Typically, oil is sold at the well-head at either (1) NYMEX average
price basis, (2) field-posted prices or (3) Platt's plus posting, less transportation costs. Typically, natural gas is sold under contract at a negotiated monthly price based upon
factors normally considered in the industry, such as processing, conditioning or treating to make gas marketable, distance from the well to the transportation pipeline, well pressure, estimated
reserves, quality of natural gas and prevailing supply/demand conditions.

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

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

Delivery Commitments

During 2007, we executed a gas gathering and compression services agreement with Frontier Midstream, LLC ("Frontier"). Following
execution of such agreement, Frontier expedited the installation of the Rose Bud system in White County, Arkansas, including the high and low pressure gathering lines, dehydration, compression and the
interconnect with Ozark, in order to accommodate our desire to be able to deliver natural gas as soon as our wells were completed. At the time of signing the contract, we had completed and tested two
productive wells in the Moorefield shale. The Rose Bud system was installed, operational and ready to deliver our production in June 2007. The contract minimum commitment to Frontier is 2.7 Bcf
over a three-year period for the pipeline interconnect. This line carries a $0.29 per Mcf deficiency rate, for a total commitment for the pipeline of approximately $0.8 million. We
have delivered approximately $63,800 of this commitment through December 31, 2008. In addition to the pipeline, Frontier also built and installed lateral gathering lines to eight locations. The
remaining commitment on these laterals is approximately $1.3 million, for a total potential liability of approximately $2.0 million to be paid by June 2010 if the minimum volumes are not
delivered. The Company recorded a long-term liability for the aggregate amount of $2.0 million in the fourth quarter of 2008. Although the Company believes there is the potential to
develop this area and increase production, it does not currently have sufficient liquidity to ensure that this occurs in the timeframe required by the gas gathering and compression services agreement
with Frontier. See Note 11 to our consolidated financial statements andITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONSLIQUIDITY AND CAPITAL RESOURCES".

17

---



Table of Contents

During
2008, we executed a gas gathering and compression services agreement with Integrys Energy Services ("Integrys") related to the construction and installation of a pipeline
connecting our Slick State properties to our Bloomberg properties in order to secure more advantageous plant processing, transportation and gathering fees and access to gas markets. The pipeline
system was installed, operational and ready to redirect our production in September 2008. The contract minimum commitment to Integrys is approximately 11.2 Bcf over a three year period for the
pipeline interconnect. The amount of total commitment is $550,000 plus 8% interest per annum, for a total liability of approximately $0.6 million. We have delivered approximately $71,400 of
this commitment through December 31, 2008. We have not recorded a liability for this commitment as we expect to meet the minimum physical delivery based on estimated anticipated production.

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

Derivatives

Due to the volatility of oil and natural gas prices, from time to time, we may enter into price-risk management
transactions (e.g., swaps, collars and floors) related to our expected oil and natural gas production to seek to achieve a more predictable cash flow, as well as to reduce exposure to commodity
price fluctuations. While the use of these arrangements may limit our ability to benefit from increases in the prices of oil and natural gas, it is also intended to reduce our potential exposure to
adverse price movements. Our arrangements, to the extent we enter into any, are intended to apply to only a portion of our expected production, and thereby provide only partial price protection
against declines in oil and natural gas prices. None of these instruments were, at the time of their execution, intended to be used for trading or speculative purposes, but a portion of these
instruments was subsequently deemed as such because of the decrease in our 2008 production. The use of derivative instruments involves some credit risk, but generally we place our derivative
transactions with major financial institutions that we believe are financially stable; however, in light of the recent global financial crisis, there can be no assurance of the foregoing. On a
quarterly basis, our management sets all of our price-risk management policies, including volumes, types of instruments and counterparties. Our Board of Directors monitors the Company's
price-risk management policies and trades on a monthly basis. We account for these transactions as derivative activities and, accordingly, certain gains and losses are included in total
revenue during the period the transactions occur. See Note 9 to our consolidated financial statements andITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONSCRITICAL ACCOUNTING POLICIES AND ESTIMATESDERIVATIVES AND HEDGING ACTIVITIES".

All
of these price-risk management transactions are considered derivative instruments and accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities(as
amended). These derivative instruments are intended to hedge our price risk and may be
considered hedges for economic purposes. There are two types of accounting treatments for derivatives, (i) mark-to-market accounting and (ii) cash flow hedge
accounting. For a discussion of these accounting treatments, see Note 9 to our consolidated financial statements. We evaluate the terms of new contracts when entered into to determine whether
cash flow hedge accounting treatment or mark-to-market accounting treatment will be applied. Prior to 2006, we used mark-to-market accounting treatment
for our crude oil derivative contracts and cash flow hedge accounting treatment for our natural gas derivative contracts. Beginning in the first quarter of 2006, we applied
mark-to-market accounting treatment to all outstanding derivative contracts. Currently all derivatives, other than those that meet the normal purchases and sales exception, are
recorded on the balance sheet at fair value and the changes in fair value are presented in total revenue on the statement of operations. Cash flows from resulting derivative settlements are included
in operating activities and investing activities on the statement of cash flows.

18

---



Table of Contents

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

Year Ended December 31,2008

2007

2006(in thousands)Natural gas contract settlements

$
(9,453
)
$
4,513

$
4,699Crude oil contract settlements


(19,259
)

(935
)

Mark-to-market reversal of prior period unrealized change in fair value of natural gas derivative contracts


(2,626
)

(4,686
)

Mark-to-market unrealized change in fair value of natural gas derivative contracts


13,390


2,626


4,686Mark-to-market reversal of prior period unrealized change in fair value of crude oil derivative contracts


14,956


(500
)

(155
)Mark-to-market unrealized change in fair value of crude oil derivative contracts


2,015


(14,956
)

500Gain (loss) on derivatives

$
(977
)
$
(13,938
)
$
9,730


The
table below summarizes our outstanding derivative contracts reflected on the balance sheet at December 31, 2008 and 2007.

Fair Value of
Outstanding
Derivative Contracts
as of December 31,Transaction
Type





Price
Per Unit

Volumes
Per DayTransaction Date

Beginning

Ending

2008

2007(in thousands)Natural Gas(1):01/07

Collar

01/01/2008

12/31/2008

$7.50-$9.00

20,000 MMBtu

$


$
1,09601/07

Collar

01/01/2008

12/31/2008

$7.50-$9.00

10,000 MMBtu





61901/07

Collar

01/01/2008

12/31/2008

$7.50-$9.02

10,000 MMBtu





59904/07

Collar

01/01/2009

12/31/2009

$7.75-$10.00

10,000 MMBtu


6,688


12510/07

Collar

01/01/2009

12/31/2009

$7.75-$10.08

10,000 MMBtu


6,702


187Crude Oil(2):12/06

Swap

01/01/2008

12/31/2008

$66.00

1,500 Bbl





(14,541
)10/07

Collar

01/01/2009

12/31/2009

$70.00-$93.55

300 Bbl


2,017


(414
)$
15,407

$
(12,329
)


---

19

---



Table of Contents

Sales to Major Customers

We sold natural gas and crude oil production representing 10% or more of our total revenues to the following major customers for the
years presented.

For the Year Ended December 31,Purchaser

2008

2007

2006Integrys Energy Services, Inc.(1)


30
%

22
%

*Kinder Morgan


18
%

20
%

37
%Gulfmark Energy, Inc.


12
%

11
%

5
%Copano Field Services


6
%

5
%

10
%ChevronTexaco, Inc.


4
%

4
%

12
%Kerr-McGee Oil & Gas


*


*


10
%


---

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

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

Competition

We compete with other oil and natural gas companies in all areas of our operations, including the acquisition of exploratory prospects
and proven properties. We will have limited ability to explore for oil and natural gas reserves and to acquire additional properties in the future. Any such exploration or other activities will be
dependent on the success of our financial and strategic alternatives process. Our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in this
highly competitive environment will also affect our exploration and other activities. SeeITEM 1A. "RISK FACTORSWe face strong
competition from larger oil and natural gas companies," and "Our January 2009 borrowing base redetermination resulted in a $114 million borrowing base deficiency under our
Revolving Facility and we may not be able to satisfy the terms and conditions of our Amended Consent relating thereto or to otherwise repay our borrowing base deficiency or satisfy our other
liabilities," and "Our ability to continue as a going concern is dependent upon a financial restructuring and/or the consummation of one or more strategic alternatives."

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

20

---



Table of Contents

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 or market 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 constitute a complete discussion of the various
statutes, rules, regulations and governmental orders to which our operations may be subject.

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

Regulation of Sales and Transportation of Natural Gas.Federal legislation and regulatory controls have historically affected the price
of natural
gas produced by us, and the manner in which such production is transported and marketed. Under the Natural Gas Act of 1938 (the "NGA"), the Federal Energy Regulatory Commission (the "FERC") regulates
the interstate transportation and the sale in interstate commerce for resale of natural gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act") deregulated
natural gas prices for all "first sales" of natural gas, including all sales by us of our own production. As a result, all of our domestically produced natural gas may now be sold at market prices,
subject to the terms of any private contracts that may be in effect. However, the Decontrol Act did not affect the FERC's jurisdiction over natural gas transportation. Under the provisions of the
Energy Policy Act of 2005 (the "2005 Act"), the NGA has been amended to prohibit any form 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 issued new regulations that are intended to increase natural gas pricing transparency through, among other things,
expanded dissemination of information about the availability

21

---



Table of Contents

and
prices of gas sold. The 2005 Act also has significantly increased the penalties for violations of the NGA.

Our
natural gas sales are affected by intrastate and interstate gas transportation regulation. Following the Congressional passage of the Natural Gas Policy Act of 1978, 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, we cannot predict whether or to what extent that trend will continue, or what
the ultimate effect will be on our
sales of gas. Again, we do not believe that we will be affected by any such new legislative proposals materially differently than any other seller of natural gas with which we compete.

We
own certain natural gas pipelines that we believe meet the standards the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA.
These gathering facilities are regulated for safety compliance by the U.S. Department of Transportation ("DOT") and/or by state regulatory agencies.

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

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

Oil Price Controls and Transportation Rates.Sales of crude oil, condensate and gas liquids by us are not currently regulated and are
made at market
prices. The price we receive from the sale of these products may be affected by the cost of transporting the products to market. Much of the transportation is through interstate common carrier
pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system
for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. The FERC's regulation of oil
transportation rates may tend to increase the cost of transporting oil and natural gas liquids by interstate pipelines, although the annual adjustments may result in decreased rates in a given year.
Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In March 2006, to
implement the second of the required five-yearly redeterminations, the FERC established an upward adjustment in the index to track oil pipeline cost changes. The FERC determined that the
Producer Price Index for Finished Goods plus 1.3 percent (PPI plus 1.3 percent) should be the oil pricing index for the five-year period beginning July 1, 2006. We are
not able at this time to predict the effects of these regulations or FERC proceedings, if any, on the transportation costs associated with oil production from our oil producing operations.

Environmental Regulations.Our operations are subject to numerous federal, state and local laws and regulations governing the discharge
of materials
into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and
concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands within
wilderness, wetlands and other protected areas, require remedial measures to eliminate or mitigate pollution from current and former operations and properties we currently own or operate or previously
owned or operated, such as pit closure, plugging abandoned wells and releases of hydrocarbons, and impose substantial liabilities for pollution resulting from production and drilling operations. A
trend of more expansive and stricter environmental legislation and regulations applied to the oil and natural gas industry has occurred and 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 operating, 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 in effect at the time, these practices have changed over time and

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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, 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, liability may be imposed, without regard to fault or the legality of the original conduct, on certain classes of persons. These persons include the current owner or operator
of the disposal site or sites where the release occurred, past owners or operators that owned or operated the site at the time of the release, and companies that disposed or arranged for the disposal
of the hazardous substances found at the site. Persons who are liable 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 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
or to pay for the foregoing.

Federal
regulations require certain owners or operators of facilities that store or otherwise handle oil, such as us, 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 administrative, civil and criminal penalties and liabilities. Our operations are also subject to the federal Clean Water Act ("CWA") and analogous state
laws. 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
and other substances into surface waters or into the ground.

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 regulatory requirements and
maintaining or obtaining permits and approvals addressing other air emission-related issues. However, we do not believe our operations will be materially adversely affected by any such requirements.

In
response to studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to warming of the Earth's atmosphere, the U.S. Congress is actively
considering climate change-related legislation to restrict greenhouse gas emissions, including carbon dioxide and methane, both of which are emitted in our operations. A number of bills being
considered propose a "cap and trade" scheme of regulation of greenhouse gas emissionsa ban on emissions above a defined reducing annual cap with covered parties authorized to emit
greenhouse emissions in a quantity decreasing through time and also through the acquisition of emission allowances that may be traded or
acquired on the open market. In addition, numerous states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas
emission inventories and/or regional greenhouse gas cap and trade programs.

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We could be required to purchase and surrender allowances. Although we do not expect to be impacted to a greater degree than other similarly situated producers of
oil and natural gas, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the oil and natural gas we produce.

Also,
as a result of the U.S. Supreme Court's decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate carbon dioxide and other greenhouse
gas emissions from mobile sources such as cars and trucks, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court's holding in Massachusettsthat greenhouse gases including carbon dioxide fall under the federal CAA's definition of "air pollutant" may also result in future
regulation of carbon dioxide and other greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New federal or state restrictions on emissions of greenhouse gases that
may be imposed in areas of the United States in which we conduct business could also adversely affect our cost of doing business and demand for the oil and natural gas we produce.

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.

ITEM 1A.    RISK FACTORS

Our January 2009 borrowing base redetermination resulted in a $114 million borrowing base deficiency under our Revolving Facility and we may
not be able to satisfy the terms and conditions of our Amended Consent relating thereto or to otherwise repay our borrowing base deficiency or satisfy our other liabilities.

In January 2009, we announced the Deficiency due to a redetermination of our borrowing base to $125 million. Pursuant to the
terms of the Revolving Facility, we elected to prepay the Deficiency in six equal monthly installments, with the first $19 million installment being due on February 9, 2009. On
February 9, 2009, we entered into the February Consent among us and the Lenders under the Revolving Facility deferring the payment date of the first $19 million installment until
March 10, 2009, and extending the due date for each subsequent installment by one month with the last of the six $19 million installment payments to be due on August 10, 2009.
Under the February Consent, we agreed to prepay $5.0 million of our outstanding advances under the Revolving Facility, in two equal installments. The first $2.5 million prepayment was
paid on February 9, 2009 and the second $2.5 million prepayment was paid on February 23, 2009 with each of the prepayments to be applied on

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a
pro rata basis to reduce the remaining six $19 million deficiency payments. On March 10, 2009, we entered into the March Consent with the Lenders under the Revolving Facility, which
provided, among other things, for the extension of the due date for the first installment to repay the Deficiency from March 10, 2009 to March 17, 2009. Notwithstanding such extension,
we agreed with the Lenders that each of the other five equal installment payments required to eliminate the Deficiency would be due and payable as provided for in the February Consent.

On
March 16, 2009, we entered into the Amended Consent which provides, among other things, (1) that we will make a $25 million payment on May 31, 2009 with
all remaining principal, fees and interest amounts under our Revolving Facility to be due and payable on June 30, 2009, (2) that it will be an event of default (i) if we fail to
have executed and delivered on or before May 15, 2009 at least one of the following (a) a commitment letter from a lender or group of lenders reasonably satisfactory to our Lenders
providing for the provision by such lender or group of lenders of a credit facility in an amount sufficient to repay all of our obligations under the Revolving Facility on or before June 30,
2009, (b) a merger agreement or similar agreement involving us as part of a transaction that results in the repayment of our obligations under the Revolving Facility on or before
June 30, 2009, and (c) a purchase and sale agreement with a buyer or group of buyers reasonably acceptable to our Lenders providing for a sale transaction by us that results in the
repayment of all of our obligations under the Revolving Facility on or before June 30, 2009, or (ii) if we are in default under or our hedging arrangements have been terminated or cease
to be effective without the prior written consent of our Lenders, (3) that our advances under the Revolving Facility will bear interest at a rate equal to the greater of (a) the
reference rate publicly announced by Union Bank of California, N.A. for such day, (b) the Federal Funds Rate in effect on such day plus 0.50% and (c) a rate determined by the
Administrative Agent to be the Daily One-Month LIBOR (as defined in the Revolving Facility), in each case plus 2.5% or, during the continuation of an event of default, plus 4.5% (resulting
in an effective interest rate of approximately 5.75% as of March 16, 2009), (4) for limitations on the making of capital expenditures and certain investments, and (5) for the
elimination of the current ratio, leverage ratio and interest coverage ratio covenant requirements. The Amended Consent also eliminates the six $19 million deficiency
payments which were contemplated by the February Consent and the March Consent. To comply with the terms of the Amended Consent, we anticipate that we will need to (i) sell select individual
assets prior to May 31, 2009 to enable us to make the $25 million payment which is due on May 31, 2009, and/or (ii) negotiate a commitment letter with a new lender or group
of lenders prior to May 15, 2009 in an amount sufficient to repay all of our obligations under the Revolving Facility on or before June 30, 2009, and/or (iii) have negotiated the
sale, merger or other business combination involving us which results in the repayment of all of our obligations under the Revolving Facility prior to May 15, 2009 and to have closed such
transaction on or before June 30, 2009. The Amended Consent limits the making of capital expenditures and we anticipate a severe curtailment of our drilling plans and other capital expenditures
in 2009.

If
we breach any of the provisions of the Amended Consent or the Revolving Facility, our Lenders will be entitled to declare an event of default, at which point the entire unpaid
principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, would become immediately due and payable. In any event, the entire unpaid
principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, will be payable on June 30, 2009 unless earlier paid or a further
extension with respect to payment is negotiated with our Lenders. Our Lenders may take action to enforce their rights with respect to the outstanding obligations under the Revolving Facility. Because
substantially all of our assets are pledged as collateral under the Revolving Facility, if our Lenders declare an event of default, they would be entitled to foreclose on and take possession of our
assets. In such an event, we may be forced to liquidate or to otherwise seek protection under Chapter 11 of the U.S. Bankruptcy Code. These matters, as well as the other risk factors related to
our liquidity and financial position raise substantial doubt as to our ability to continue as a going concern. SeeITEM 7. "MANAGEMENT'S DISCUSSION

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AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSLIQUIDITY AND CAPITAL RESOURCESREVOLVING
FACILITY."With respect to our compliance with the Amended Consent, there can be no assurance that we will be able to further negotiate the terms of the Amended Consent or
negotiate a further restructuring of the related indebtedness or that we will be able to make any required payments when they become due. Moreover, there can be no assurance that we will be successful
in our efforts to comply with the terms of the Amended Consent, including our ongoing efforts to evaluate and assess our various financial and strategic alternatives (which may include the sale of
some or all of our assets, a merger or other business combination involving the Company, or the restructuring or recapitalization of the Company). If such efforts are not successful, we may be
required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

Our ability to continue as a going concern is dependent upon a financial restructuring and/or the consummation of one or more strategic alternatives.

In addition to the Deficiency under our Revolving Facility, the capital expenditures required to maintain and/or grow production and
reserves are substantial. Our stock price has significantly declined over the past year which makes it more difficult to obtain equity financing on
acceptable terms to address our liquidity issues. In addition, we are reporting negative working capital at December 31, 2008 and a third consecutive year of net losses for the year ended
December 31, 2008, which is largely the result of impairments of our oil and natural gas properties. We have also recently substantially curtailed our operations due to reduced liquidity and a
lack of external financing alternatives. Therefore, there is substantial doubt as to our ability to continue as a going concern for a period longer than the current fiscal year. Our independent
auditors have included an explanatory paragraph in their report on our consolidated financial statements that raises substantial doubt about our ability to continue as a going concern See
ITEM 8."FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAReport of the Independent Registered Accounting Firm." Our ability to continue
as a going concern is dependent upon the success of our financial and strategic alternatives process, which may include the sale of some or all of our assets, a merger or other business combination
involving the Company or the restructuring or recapitalization of the Company. Until the possible completion of the financial and strategic alternatives process, our future remains uncertain and there
can be no assurance that our efforts in this regard will be successful.

Our
business requires substantial working capital to fund ongoing exploration, development and acquisition programs, and our financial condition is dependent, at least in part, upon our
ability to access capital at rates and on terms we determine to be attractive which has recently become exceptionally difficult. In addition, the significant declines in the prices of our stock have
made it even more difficult for us to effectively raise capital by accessing the equity markets. In order to generate incremental cash flows, we need to drill productive oil or natural gas wells.
Because we do not currently have sufficient access to capital either from equity markets or our Revolving Facility, we will need to raise the funds required to drill new wells from third parties
willing to pay our share of the costs of drilling and completing the wells. We may not be successful in raising such capital and we currently do not have any availability under our Revolving Facility.
In addition, we are limited in our ability to expend capital under the terms of the Amended Consent. Any future wells which we may drill may not be productive of oil or natural gas. Our inability to
generate cash flows may force us to further curtail or cease certain operations. Further sales of producing properties may further reduce our ability to borrow and to benefit from any future cash flow
attributable to those properties. If our operations do not provide the liquidity required to operate our business, our drilling and other activities may be further curtailed, our cash flow and
financial condition would be further materially adversely affected and we would become highly vulnerable to further adverse general economic consequences and industry conditions. In such event, we may
be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

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As
discussed above, in January 2009 the Lenders to our Revolving Facility completed their borrowing base redetermination and reduced our borrowing base to $125 million, resulting
in a borrowing base deficiency of $114 million and we recently entered into the Amended Consent relating to the repayment of our obligations under the Revolving Facility. As further discussed
above, we will need to take certain actions to comply with the terms of the Amended Consent. Absent our success with respect to such actions, we will be unable to comply with the terms of the Amended
Consent and make the payments due thereunder.

There
can be no assurance that we will be able to further negotiate the terms of the Amended Consent or a further restructuring of the related indebtedness or that the Company will be
able to make any required payments when they become due. We have retained an investment banking firm to assist further in the evaluation of our strategic and financial alternatives. There can be no
assurance that the Company's ongoing efforts to evaluate and assess its various financial and strategic alternatives (which may include the sale of some or all of our assets, a merger or other
business combination involving the Company, or the restructuring or recapitalization of the Company) will be successful. If such efforts are not successful, the Company may be required to seek
protection under Chapter 11 of the U.S. Bankruptcy Code.

Even
if we are able to address our immediate liquidity issues, our history of losses may impair our ability to obtain financing for drilling and other business activities on favorable
terms or at all. It may also impair our ability to attract investors if we attempt to raise additional capital to grow our business, or for other business purposes, by selling additional debt or
equity securities in a private or public offering. If we are unable to obtain additional financing, we may be unable to maintain and develop our properties and if such efforts are not successful, the
Company may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

Our Revolving 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 and proved reserve amounts resulted in increased estimated discounted future net
revenue which allowed us to increase our available borrowing amounts. Recently commodity prices have rapidly declined and therefore reserve estimates have been revised, which has impacted our
borrowing base. More specifically and as discussed above, our borrowing base has been reduced to $125 million resulting in a borrowing base deficiency of $114 million. Our obligations
under the Revolving Facility are secured by a pledge of substantially all of our assets. The Revolving Facility has covenants that limit additional borrowings, sales of assets and the distributions of
cash or properties and that prohibit the payment of dividends on our common stock and the incurrence of liens. For the foreseeable future, we will not have borrowing capacity under our Revolving
Facility. We intend to continue to monitor closely our cash position and are limiting our capital and other expenditures. The restrictions of our Revolving Facility and the difficulty in obtaining
additional debt financing will 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 (if it is able to be obtained), 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 would further reduce the funds that would otherwise be available for operations and future business opportunities. Further, a decrease in
our operating cash flow or an increase in our expenses will make it even more difficult for us to meet debt service requirements and require us to further modify operations, and thus we would become
even more vulnerable to continued downturns in our business or the economy generally.

Our
ability to obtain and service indebtedness will depend on our ability to restructure our debt or pursue strategic alternatives as well as 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

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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. In this regard, we do not expect that our current cash flow will be in an amount sufficient to enable us to service our existing indebtedness or to make
capital expenditures or finance our drilling program beyond that currently contemplated by our reduced capital budget. 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 further curtail our drilling program, sell assets, reduce capital expenditures, refinance all or a portion of our existing
debt or obtain additional financing. We may not be able to refinance our debt or obtain additional financing, particularly in view of our financial and strategic alternatives process, current industry
conditions, the restrictions on our ability to incur debt under our existing debt arrangements, and the fact that substantially all of our assets are currently pledged to secure obligations under our
Revolving Facility. SeeITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSLIQUIDITY AND
CAPITAL RESOURCES" and "REVOLVING FACILITY." If such efforts are not successful, the Company may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

We need to replace our reserves at a faster rate than companies whose reserves have longer production periods. Our failure to replace our reserves
will result in decreasing reserves and production over time.

Unless we conduct successful exploration and development activities or acquire properties containing proven reserves, our estimated
proved reserves will decline as reserves are depleted. Producing oil and natural gas reserves are generally characterized by declining production rates that vary depending on reservoir characteristics
and other factors. High production rates generally result in recovery of a relatively higher percentage of reserves from properties during the initial few years of production. A significant portion of
our current operations are conducted in onshore Texas. Production from reserves in onshore Texas generally declines more rapidly than reserves from reservoirs in other producing regions. As a result,
our need to replace reserves from new investments is relatively greater than those of producers who produce their reserves over a longer time period, such as those producers whose reserves are located
in areas where the rate of reserve production is lower. If we are not able to find, develop or acquire additional reserves to replace our current and future production, our production rates will
decline even if we drill the undeveloped locations that were included in our estimated proved reserves. Our future oil and natural gas reserves and production, and therefore our cash flow and income,
are dependent on our success in economically finding or acquiring new reserves and efficiently developing our existing reserves. Our severely limited drilling program will restrict our ability to add
to our reserve base for the foreseeable future.

Our common stock could be delisted from The NASDAQ Global Select Market, which could negatively impact the price of our common stock and our ability
to access the capital markets. If we are delisted by The NASDAQ Global Select Market before we are able to be listed on another national stock exchange or approved for quotation on an
over-the-counter market in the United States, we may be required to repurchase our outstanding Convertible Preferred Stock at 100% of its liquidation preference, plus any
accumulated and unpaid dividends. If this were to occur, there would be a material adverse effect on our business, financial condition and results of operations.

Our common stock is currently listed on The NASDAQ Global Select Market. The listing standards of The NASDAQ Global Select Market
provide, among other things, that a company may be delisted if the bid price of its stock drops below $1.00 for a period of 30 consecutive business days. In October 2008, The NASDAQ Stock Market
suspended enforcement of the $1.00 minimum bid requirement and the minimum market capitalization requirements through January 16, 2009 due to the rapid deterioration of the capital markets. In
December 2008, given the continued extraordinary market conditions, The NASDAQ Stock Market extended its suspension of the $1.00 minimum bid

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requirement
and the minimum market capitalization requirements through April 19, 2009. If we fail to comply with the listing standards, our common stock listing may be moved to The NASDAQ
Capital Market, which is a lower tier market, or our common stock may be delisted and traded on the over-the-counter bulletin board network. Moving our listing to The NASDAQ
Capital Market or other markets could adversely affect the liquidity of our common stock and the delisting of our common stock would significantly affect the ability of investors to trade our
securities and could significantly negatively affect the value of our common stock. In addition, the delisting of our common stock could further depress our stock price and materially adversely affect
our ability to raise capital on terms acceptable to us, or at all. Delisting from NASDAQ could also have other negative results, including the potential loss of confidence by suppliers and employees,
the loss of institutional investor interest and fewer business development opportunities. At this time, absent a further continued suspension of the $1.00 minimum bid requirement and the minimum
market capitalization requirements, we do not believe that we would be able to meet The NASDAQ Global Select Market listing standards.

If
our shares are delisted from The NASDAQ Global Select Market and we are unable to list our common stock on another national securities exchange or an
over-the-counter market in the United States prior to such delisting, the holders of all of our 5.75% Series A cumulative convertible perpetual preferred stock (the
"Convertible Preferred Stock") have a "put" right to require us to repurchase our Convertible Preferred Stock at a price in cash equal to 100% of the liquidation preference, plus accumulated and
unpaid dividends. We do not currently have the liquidity necessary to repurchase our Convertible Preferred Stock and our ability to issue common stock in connection such repurchase may be limited. In
the event that this put right were exercised and we were unable to pay the repurchase price in either cash or common stock, we may be required to seek protection under Chapter 11 of the U.S.
Bankruptcy Code.

The current financial crisis and recession has negatively impacted the prices for our oil and natural gas production, limited access to the credit
and equity markets, increased the cost of capital, and may have other negative consequences that we cannot predict.

Our operations are affected by local, national and worldwide economic conditions. The consequences of a recession may include a lower
level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might also result in a decline in energy consumption, which
may adversely affect our revenue, liquidity and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise
capital. The events discussed above, together with our liquidity level and our recent financial performance, increase the likelihood that we would become highly vulnerable to further adverse general
economic consequences and industry conditions and that our cash flow and financial condition may be materially adversely affected as a result thereof. See "Our Revolving Facility has
substantial operating restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect operations."

The
continued credit crisis and related turmoil in the global financial system and economic recession in the U.S. create financial challenges if conditions do not improve. In response to
these crises, our existing Deficiency and declining natural gas and oil prices, we have reduced and refocused our 2009 capital budget. Historically we have accessed the capital markets to provide us
with additional capital in addition to our cash flow from operations, our Revolving Facility and cash on hand. Our ability to access the capital markets has been restricted as a result of this crisis
and may continue to be restricted at a time when we would like, or need, to raise capital. If our cash flow from operations does not improve and our access to capital is restricted, we may be required
to further reduce our operating and capital budget, which could have a further material adverse effect on our results and future operations. The financial crisis may also limit the number of
participants or reduce the values we are able to realize in asset sales or other transactions we may engage in to raise capital, making these

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transactions
more difficult to consummate. Additionally, the current economic situation has affected the demand for natural gas and oil and has resulted in lower prices for natural gas and oil, which
will have a negative impact on our revenues. Lower prices could also adversely affect the collectability of our trade receivables and cause our hedging arrangements to be unsuccessful if our
counterparties are unable to perform their obligations.

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

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

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

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

In
connection with the Deficiency, we retained an investment banking firm to further assist us in an evaluation of our strategic alternatives, including a capital restructuring for the
Company, a merger or other business combination involving the Company or the sale of some or all of the Company's assets. There can be no assurance that the Company will be successful in pursuing any
such alternative. Moreover, there can be no assurance that the Company's ongoing efforts to evaluate and assess its various financial and strategic alternatives (which may include the sale of some or
all of the Company's assets, a merger or other business combination involving the Company, restructuring of the Company's debt or the issuance of additional equity or debt) will be successful. If such
efforts are not successful, the Company may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

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. Recently there
has been a strong demand for professionals in the oil and natural gas industry including geologists, geophysicists, engineers and other professionals. We believe that our success is dependent upon our
ability to continue to employ and retain skilled technical personnel; however, current market conditions for professionals as well as uncertainty relating to the outcome of the financial and strategic
alternatives process and the termination of the proposed merger with Chaparral has resulted in the departure of employees. Although we believe that we have thus far obtained replacements adequate for
our current needs, the cumulative effect of these employee departures with additional departures could materially adversely
affect us. SeeITEM 4. "SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERSEXECUTIVE OFFICERS OF THE REGISTRANT" and
"SIGNIFICANT EMPLOYEES."

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

Any future growth and maintenance of our reserves will be materially dependent upon the success of our future drilling program which is
currently being severely curtailed. Drilling for oil and gas involves numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The cost of
drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including
unexpected drilling conditions, pressure or irregularities in formations, unexpected communication with water-bearing zones, equipment failures or accidents, adverse weather conditions, compliance
with governmental requirements and shortages or delays in the availability of drilling rigs or crews and the delivery of equipment. Our future drilling activities may not be successful or may be
significantly curtailed and, if unsuccessful or curtailed, such failure or curtailment 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 can be difficult to predict and may vary from our capital budget. The final determination with respect to the drilling of any scheduled or
budgeted wells will be dependent on a number of factors, including:



These
projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive oil or natural gas. Our drilling operations have been
severely curtailed as a result of our current liquidity issues and we expect to maintain a drilling program which is severely limited and which is not likely to result in effectively replacing the
reserves that we produce. SeeITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSGENERAL
OVERVIEWINDUSTRY AND ECONOMIC FACTORS" andITEMS 1 AND 2. "BUSINESS AND PROPERTIESCORE AREAS OF OPERATION."

Oil and natural gas prices are highly volatile in general and low prices negatively affect our financial results and may further impact our borrowing
base under our Revolving Facility resulting in additional borrowing base deficiencies.

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

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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 further impact our borrowing base under our Revolving Facility resulting in additional borrowing base deficiencies in excess of our current Deficiency and materially
adversely affect our financial condition, liquidity, and ability to finance planned capital expenditures and operations. This borrowing base deficiency was largely the result of lower commodity prices
and increased costs which impacted the reserve calculation used to redetermine our borrowing base along with our inability to replace and increase our reserves over the last year. See ITEM 7."MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONSRISK MANAGEMENT ACTIVITIESDERIVATIVES AND HEDGING" andITEMS 1 AND 2."BUSINESS AND PROPERTIESOIL AND NATURAL GAS RESERVES" and "MARKETING."

We
have in the past (most recently in the third and fourth quarters of 2008) and may in the future be required to write down the carrying value of our oil and natural gas properties.
This may happen for several reasons, including a revision in reserve estimates and depression or unusual volatility in oil and natural gas prices. Whether we will be required to take such a charge
will depend on the prices for oil and natural gas at the end of any quarter (or at the respective subsequent pricing date) and the effect of reserve additions or revisions and capital expenditures
during such quarter. If a write down is required, it would result in a charge to earnings, but would not impact cash flow from operating activities.

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

In order to reduce our exposure to short-term fluctuations in the price of oil and natural gas, we periodically enter into
hedging arrangements. At the time we enter into our hedging arrangements, they are intended to apply to only a portion of our expected production and thereby provide only partial price protection
against declines in oil and natural gas prices. The use of hedging arrangements involves some credit risk, but generally we place our derivative transactions with major financial institutions that we
believe are financially stable; however, in light of the recent global financial crisis, there can be no assurance of the foregoing. Our hedging arrangements may also expose us to risk of financial
loss in certain circumstances, including instances where production is less than expected, our customers fail to purchase contracted quantities of oil or natural gas or a sudden, unexpected event
materially impacts oil or natural gas prices. In that regard, our changes in 2008 production and asset divestitures resulted in our derivative contracts covering approximately 115% and 190% of our
2008 natural gas and crude oil production, respectively. This overhedged position exposed us to greater risk of commodity price increases because we did not have the physical production cash inflows
to offset the losses incurred on the portion of the contracts that were overhedged. SeeITEM 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DERIVATIVES."

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

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline
depending on reservoir characteristics. Except to the extent we acquire properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves
will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent upon our level of success in finding or acquiring additional reserves.

If
we fail to replace reserves though drilling or acquisitions, our level of production and cash flows will be adversely affected. Our ability to make the necessary capital investment to
maintain or expand our asset base of oil and gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not
be successful in exploring for, developing or acquiring additional reserves. We intend to dedicate the majority of our capital expenditures in the immediate future to further developing a limited
selection of properties which will
limit our ability to replace the reserves that we produce. Exploration activities involve numerous risks, including the risk that no commercially productive natural gas reservoirs will be discovered
and/or recoverable. In addition, the future cost and timing of drilling, completing and tying-in wells are often uncertain. Our exploration and development operations may be curtailed,
delayed or cancelled as a result of a variety of factors, including, inadequate capital resources, reductions in oil and natural gas prices and limitations in the market for oil and natural gas. 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.

Our
ability to maintain or increase our reserves will be constrained as we comply with the terms of the Amended Consent which will reduce our capital expenditures and drilling
activities. To the extent that we are unable to obtain additional financing to fund our exploration and development activities, our reserves will further decline and our borrowing base under our
Revolving Facility could be further adjusted downward.

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

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properties
operated by others therefore depend upon a number of factors outside of our control, including the operator's



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

We have experienced and expect to continue to experience substantial working capital needs due to our ongoing exploration, development
and acquisition programs.
Additional financing will 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 further curtailed and we expect that our drilling and other activities
will be significantly curtailed in 2009 as we comply with the terms of the Amended Consent and pursue strategic alternatives. SeeITEM 7."MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSLIQUIDITY AND CAPITAL RESOURCES."

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

Due to industry demands, well service providers and related equipment and personnel may be in short supply as has occurred in recent
years. This could cause 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. In addition, even though commodity prices have rapidly declined in recent months, the costs of field services and equipment have not declined as rapidly.

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 relating to worker safety and 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 pollution and environmental damages we cause or related to facilities we currently or formerly owned or operated, even if 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."

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

The oil and gas industry is highly competitive. We encounter competition from oil and natural gas companies in all areas of our
operations, including the acquisition of exploratory prospects and productive oil and natural gas properties. Our competitors range in size from the major integrated oil and natural gas companies to
numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of these competitors are large, well-established companies with substantially larger
operating staffs and greater capital resources than ours. We may not be able to conduct our operations successfully, evaluate and select suitable properties, consummate transactions, and obtain
technical, managerial and other professional personnel in this highly competitive environment. Moreover, our ability to explore for or acquire oil and natural gas reserves will be limited as a result
of our ongoing financial and strategic alternatives process, the Amended Consent and the challenges and uncertainty facing our company currently. Additionally, larger competitors may be able to pay
more for exploratory prospects, productive oil and natural gas properties and competent personnel and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects
than our financial or human resources permit. In addition, such competitors may be able to expend greater resources on the existing and changing technologies that we believe are and will be
increasingly important to attaining success in the industry. Such competitors may also be in a better position to secure oilfield services and equipment on a timely
basis or on favorable terms. SeeITEMS 1 AND 2."BUSINESS AND
PROPERTIESCOMPETITION."

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

Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be
measured in an exact manner and is based upon assumptions that may vary considerably from actual results. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual
production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. The information regarding discounted future net cash flows
included in this report should not be considered as the current market value of the estimated oil and natural gas reserves attributable to our properties. As required by the SEC, the estimated
discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual
future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and natural gas, increases or decreases in consumption, and changes
in governmental regulations or taxation. In addition, the 10% discount factor, which is required by the Financial Accounting Standards Board in Statement of Financial Accounting Standards ("SFAS")
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."

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 and our insurance does not protect against loss of revenue. We cannot predict the continued availability of insurance
and 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

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covered
by insurance could have a material adverse effect on our financial condition and results of operations.

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

At December 31, 2008, we had estimated net operating loss carryforwards ("NOLs") of $124.9 million, without consideration
of valuation allowance for federal income tax purposes that expire beginning in 2012. We also had state NOL carryforwards at December 31, 2007 of $21.4 million, without consideration of
valuation allowance, which will expire in varying amounts between 2009 and 2028. Due to recurring losses in recent years, utilization of the Company's NOL's may not be more likely than not, which
would require the Company to establish a valuation allowance against the related deferred tax asset on the books. See Note 17 to our consolidated financial statements. Our ability to utilize
federal and state NOL carryforwards in cases where the NOL was acquired in a reorganization may be subject to limitations under Section 382 of the Internal Revenue Code of 1986, as amended
("Section 382"), if we undergo a majority ownership change as defined by Section 382.

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

At
December 31, 2008, under Section 382 rules, approximately $80.5 million of our total federal NOL carryforward of $124.9 million was subject to a potential
annual limitation of $12 million. Of that $80.5 million, $22 million was subject to further annual limitations. The $22 million amount represents the following two separate
limitations which occurred prior to 2008: (1) $17.4 million acquired in a December 2003 merger, which is subject to an annual limitation of approximately $1 million per year and
(2) $5.4 million acquired in a November 2005 acquisition, which is subject to an annual limitation of approximately $2 million per year.

Approximately 21% of our proved reserves were undeveloped as of December 31, 2008, and those reserves may not ultimately be developed.

As of December 31, 2008, approximately 21% of our proved reserves were undeveloped. Proved undeveloped reserves, by their
nature, are less certain than other categories of proved reserves. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations and involves greater
risks. Our reserve data for the properties assumes that to develop our reserves we will make significant capital expenditures and conduct these operations successfully. Although we have prepared
estimates of these natural gas and oil reserves and the costs associated with

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these
reserves in accordance with industry standards and SEC requirements, the estimated costs may not be accurate, development may not occur as scheduled and actual results may not be as estimated.
In addition, the current curtailment of our drilling program in response to our ongoing liquidity issues and our compliance with the Amended Consent will make it unlikely that we will be able to
develop these reserves in the foreseeable future.

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

We have not historically paid a dividend on our common stock, cash or otherwise, and do not intend to in the foreseeable future. We are
currently restricted from paying dividends on common stock by our existing Revolving Facility and, in some circumstances, by the terms of our Convertible Preferred Stock. Any future dividends also may
be restricted by our then-existing debt agreements. SeeITEM 7."MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONSLIQUIDITY AND CAPITAL RESOURCES" and Notes 11 and 13 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 General Corporation Law of the State of Delaware 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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ITEM 1B.    UNRESOLVED STAFF COMMENTS

None.

CERTAIN DEFINITIONS

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

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

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

Bbls/d.Stock tank barrels per day.

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.

British Thermal Unit or BTU.The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

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.

Condensate.Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

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

Development costs.Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and
storing the
oil and gas. This definition of development costs has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of
Regulation S-X. The entire definition of this term can be viewed on the website at http://www.sec.gov/about/forms/forms-x.pdf.

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

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

Exploration costs.Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered
to have
prospects of containing oil and gas reserves, including costs of drilling exploratory wells. This definition of exploratory costs has been abbreviated from the applicable definitions contained in
Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the website at http://www.sec.gov/about/forms/forms-x.pdf.

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

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

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

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

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

Lease operating expenses.The expenses of lifting oil or gas from a producing formation to the surface, and the transportation and
marketing thereof,
constituting part of the current operating expenses of a
working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, ad valorem taxes and other expenses incidental to production,
but not including lease acquisition or drilling or completion expenses.

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

Mcf.One thousand cubic feet.

Mcf/d.One thousand cubic feet per day.

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

MMBtu.Million British Thermal Units.

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

NGL's.Natural gas liquids measured in barrels.

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NRIornet revenue interests.The share of production after satisfaction of all royalty,
overriding
royalty, oil payments and other nonoperating interests.

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

Operator.The individual or company responsible for the exploration and/or exploitation and/or production of an oil or gas well or
lease.

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

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

Plugging and abandonment.Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum
will not escape
into another or to the surface. Regulations of many states require plugging of abandoned wells.

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

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

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

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

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

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

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

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

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

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.

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Table of Contents

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

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

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

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

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

ITEM 3.    LEGAL PROCEEDINGS

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

David Blake, et al. v. Edge Petroleum CorporationOn September 19, 2005, David Blake and David Blake, Trustee of the David and Nita Blake
1992
Children's Trust, filed suit against us in state district court in Goliad County, Texas alleging breach of contract for failure and refusal to transfer overriding royalty interests to plaintiffs in
several leases in the Nita and Austin prospects in Goliad County, Texas and failure and refusal to pay monies to Blake pursuant to such overriding royalty interests for wells completed on the leases.
The plaintiffs seek relief of (1) specific performance of the alleged agreement, including granting of overriding royalty interests by us to Blake; (2) monetary damages for failure to
grant the overriding royalty interests; (3) exemplary damages for his claims of business disparagement and slander; (4) monetary damages for tortious interference; and
(5) attorneys' fees and court costs. Venue of the case was transferred to Harris County, Texas by agreement of the litigants. Our subsidiaries, Edge Petroleum Exploration Company, Edge
Petroleum Operating Company and Edge Petroleum Production Company, were also added as defendants. We filed a counterclaim against plaintiff Blake and joined various related entities that are
controlled by Blake, seeking lease interests in which we contend we had been wrongfully denied participation and also claiming that proprietary information was misappropriated. The parties have moved
for summary judgment on each other's claims and counterclaims, which the trial court has denied as to both sides. In November 2007, we filed a separate motion for summary judgment based on the statute
of frauds and; the court has not yet ruled on this separate motion. In June 2008, the plaintiffs filed a Sixth Amended Petition conditionally adding claims for certain prospects that had been
previously settled by means of a Compromise and Settlement Agreement (the "Settlement Agreement"), entered in settlement of prior litigation among some of the parties, but only to the extent that
rescission of the prior Settlement Agreement was being sought by us. We are not seeking rescission of the prior Settlement Agreement and responded accordingly in our Fourth Amended Original
Counterclaim and Claims Against Additional Parties filed on October 16, 2008. On October 17, 2008, the plaintiffs filed their Seventh Amended Petition adding a claim for breach of the
Settlement Agreement. The trial, originally scheduled to begin September 10, 2007, has been reset several times, most recently for December 8, 2008, and will be reset in 2009 by the
newly-elected judge of the 215th Judicial District Court. In December 2008, one of the Blake counter-defendants filed a motion to arbitrate, which motion has not been heard by the court.
Extensive written discovery has occurred in the case, and the parties are engaging in fact and expert witness depositions.

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We
have responded and will continue to respond aggressively to this lawsuit, and believe we have meritorious defenses and counterclaims.

Diana Reyes, et al. v. Edge Petroleum Operating Company, Inc., et al.On January 8, 2008, we were served with a wrongful death action
filed in Hidalgo County, Texas. Plaintiffs allege negligence and gross negligence resulting from a fatality accident at the Slick State B-12 well site, on our Bloomberg Flores lease in
Starr County, Texas. The plaintiffs are the widow and minor children of Mr. Reyes, who was killed in a one-car fatality accident on August 5, 2007. Mr. Reyes was an
employee of Payzone Logging, a vendor of ours. In September 2008, the defendants in this case, including us, reached a settlement with the plaintiffs in the amount of $175,000, all of which was paid
by third party insurance. Neither we nor our insurance carrier were required to contribute to the settlement pool. This matter was dismissed by the court on December 17, 2008.

Mary Jane Carol Trahan Champagne, et al. v. Edge Petroleum Exploration Company, et al.On September 19, 2008 we were sued in state district
court in Vermilion Parish, Louisiana by Mary Jane Trahan, Carol Trahan Champagne and 29 other plaintiffs alleging breach of obligations under mineral leases in Vermilion Parish regarding the Trahan
No. 1 well and the Trahan No. 3 well (MT RC SUB reservoir). Plaintiffs are seeking unspecified damages for lost revenue, lost royalties and devaluation of property interest sustained as
a result of the defendants' alleged negligent and improper drilling operations on the Trahan No. 1 well and the Trahan No. 3 well, including alleged failure to prevent underground water
from flooding and destroying plaintiffs' portion of the reservoir beneath plaintiffs' property. Plaintiffs also allege defendants failed to "block squeeze" sections of the Trahan No. 3 well as
would a prudent operator. This lawsuit, previously removed from the state court to the federal district court for the Western District of Louisiana, Lafayette Division, has been remanded to state
court. Our insurance carrier has retained counsel to represent us in this matter. We have not established a reserve with respect to this claim and it is not possible to determine what, if any, our
ultimate exposure might be in this matter. We intend to vigorously defend ourselves in this lawsuit.

John Lemke, et al. v. Edge Petroleum CorporationIn October 2008, we were sued by alleged assignees of Continental Seismic over an alleged
contract to
receive a royalty of two-tenths of one percent in certain alleged areas developed for oil and gas in South Louisiana. We have filed an answer generally denying the allegations and raising
the defenses of the statute of limitations bar and laches. No discovery has been served. The court recently entered a docket control order which establishes a discovery timetable and a trial date of
November 30, 2009. We have not established a reserve with respect to this claim and we have not determined what, if any, our ultimate exposure might be in this matter. We will respond
aggressively to this lawsuit, and believe we have meritorious defenses.

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

Our stockholders voted on the following matters at the Annual Meeting of Stockholders on December 29, 2008:

For

Against

Withheld

Abstain

Broker Non-
Votes(A)

Election of Directors:Vincent S. Andrews


24,911,162





2,268,915





Jonathan M. Clarkson


24,849,694





2,330,383





Michael A. Creel


24,746,747





2,433,330





(B)

Approval of the Appointment of BDO Seidman, LLP as Independent Registered Public Accounting Firm for 2008


26,171,474


871,300





137,303





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In
addition to the election of the directors indicated above, the following directors continued as directors following the meeting: Thurmon M. Andress, John W. Elias, John
Sfondrini, Robert W. Shower and David F. Work.

Executive Officers of the Registrant

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

John W. Eliashas served as the Chief Executive Officer and Chairman of the Board of the Company since November 1998. From April
1993 to September 30, 1998, he served in various senior management positions, including Executive Vice President, of Seagull Energy Corporation, a company engaged in oil and natural gas
exploration, development and production and pipeline marketing. Prior to April 1993, Mr. Elias served in various positions for more than 30 years, including senior management positions
with Amoco Corporation, a major integrated oil and gas company. Mr. Elias holds a B.S. from Oklahoma University and is a graduate of the Advanced Management Program at Harvard University.
Mr. Elias has more than 45 years of experience in the oil and natural gas exploration and production business. He is 68 years old.

Gary L. Pittmanhas served as Executive Vice President and Chief Financial Officer of the Company since January 26, 2009.
Prior to joining the Company, Mr. Pittman served as the Vice President of Special Projects at Tronox Incorporated from September 2008 to January 2009. Mr. Pittman has experience as Chief
Financial Officer of four public companies of which three were E&P related. In addition, he has extensive experience with turnarounds and has also served as Vice President and Chief Financial Officer
of Vermilion Companies from March 2008 to September 2008; as Chief Financial Officer from December 2002 to August 2007, Senior Vice President and Secretary from May 2006 to August 2007 and Treasurer
from August 2004 to August 2007 of Pioneer Companies, Inc.; and as Vice President and Chief Financial Officer of Coho Energy, Inc. from 2000 to 2002. Mr. Pittman holds a B.A. and
M.B.A. from Oklahoma University. He is 53 years old.

John O. Tugwellhas served as Chief Operating Officer and Executive Vice President since April 2005 and prior to that served as
Chief Operating Officer and Senior Vice President of Production for the Company since March 2004. Prior to that, he served as Senior Vice President of Production since December 2001. Prior to that,
Mr. Tugwell served as Vice President of Production since March 1997. He served as Senior Petroleum Engineer of the Company's predecessor corporation since May 1995. From 1986 to May 1995,
Mr. Tugwell held various reservoir/production engineering positions with Shell Oil Company, most recently that of Senior Reservoir Engineer. Mr. Tugwell holds a B.S. in Petroleum
Engineering from Louisiana State University. Mr. Tugwell is a registered Professional Engineer in the State of Texas. Mr. Tugwell is 45 years old.

Significant Employees

Howard Creaseyhas served as the Senior Vice President of Exploration since October
2006 and prior to that as the Vice President of Exploration since October 2005. Before October 2005, Mr. Creasey was Chief Geologist for the Company since October 2003. From April 1999 until
October 2003 he served as a Senior Staff Geologist for Devon Energy and its predecessor Ocean Energy. Prior to April 1999 for 14 years Mr. Creasey served as President and Exploration
Geologist for Moss Rose Energy, Inc., a company he started in 1986. Mr. Creasey holds a B.S. in Geology from Stephen F. Austin State University, has been a member of the AAPG for
over 25 years and is a Certified Geoscientist in the State of Texas. Mr. Creasey is 53 years old.

Kirsten A. Hinkhas served as Chief Accounting Officer since July 2008 and Vice President and Controller of the Company
since October 2003. She served as Controller of the Company from December 31, 2000 to October 2003. Prior to that time she served as Assistant Controller from June

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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 42 years old.

C.W. MacLeodhas served as the Senior Vice President Business Development and Planning for the Company since April 2004 and Vice President
Business Development and Planning for the Company since January 2002. From July 2008 to January 2009, he also served as our Acting Chief Financial Officer. From November 1999 to December 2001,
he was Vice PresidentInvestment Banking with Raymond James and Associates, Inc. From February 1990 to October 1999, Mr. MacLeod was a principal with Kirkpatrick Energy
Associates, Inc., whose principal business was merger and acquisition services, capital arrangement and analytical services for the oil and gas producing industry. Mr. MacLeod was
responsible for originating corporate finance and research products for energy clients. His previous experience includes positions as an independent petroleum geologist, a manager of exploration and
production for an independent oil and gas producer and geologic positions with Ladd Petroleum Corporation and Resource Sciences Corporation. Mr. MacLeod graduated from Eastern Michigan
University with a B.S. in Geology and earned his M.B.A. from the University of Tulsa. He is 58 years old.

R. Keith Turnerhas served as Vice President of Land for the Company since September 2006. Before moving to the Land Department,
Mr. Turner was a Staff Attorney in the Legal Department since 2003. Prior to joining the Company in 2003, Mr. Turner served in various capacities with Newfield Exploration Company, Fina
Oil and Chemical Company and Torch Energy Advisors, Inc. He received a B.S. in Science from Stephen F. Austin State University and a J.D. degree from South Texas College of Law.
Mr. Turner is 54 years old.

Robert C. Thomashas served as Senior Vice President, General Counsel and Corporate Secretary since October 2006 and prior to that
as Vice President, General Counsel and Corporate Secretary since March 1997. From February 1991 to March 1997, he served in similar capacities for the Company's corporate predecessor. From 1988 to
January 1991, he was associate and acting general counsel for Mesa Limited Partnership in Amarillo, Texas. Mr. Thomas holds a B.S. degree in Finance and a J.D. degree in Law from the University
of Texas at Austin. He is 55 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 12, 2009, we estimate there were approximately 208 record holders of our common stock. Our common stock is
listed on The NASDAQ Global Select Market ("NASDAQ") and traded under the symbol "EPEX". As of March 12, 2009, we had 28,836,927 shares of common stock outstanding and our closing price on
NASDAQ was $0.11 per share. The following table sets forth, for the periods indicated, the high and low closing sales prices for our common stock as listed on NASDAQ.

Common Stock PricesHigh
($)

Low
($)Calendar 2008First Quarter


6.96


3.75Second Quarter


5.81


4.04Third Quarter


6.10


1.56Fourth Quarter


1.92


0.06Calendar 2007First Quarter


18.23


11.62Second Quarter


15.78


12.30Third Quarter


15.20


11.90Fourth Quarter


13.05


5.21


We
have never paid a dividend on our common stock, cash or otherwise, and do not intend to in the foreseeable future. In addition, under our Revolving 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.
SeeITEM 1A. "RISK FACTORSWe do not intend to pay dividends on our common stock and our ability to pay dividends on our common stock is
restricted."

There
were no repurchases of securities during the fourth quarter of 2008.

Performance Graph

The following performance graph compares the cumulative total stockholder return on the common stock to the cumulative total return of
the Standard & Poor's 500 Stock Index ("S&P 500 Index") and an index composed of all publicly traded oil and gas companies identifying themselves by primary Standard Industrial
Classification ("SIC") Code 1311 (Crude Petroleum and Natural Gas) for the period beginning December 31, 2003 and ending December 31, 2008.

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Table of Contents

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

GRAPHIC

The
graph assumes that $100 was invested on December 31, 2003 in each of Edge common stock, the S&P 500 Index and the SIC Code 1311 companies and assumes that all dividends
were reinvested:

Edge Petroleum

SIC Code Index

S&P 500 IndexDecember 31, 2003

$
100.00

$
100.00

$
100.00December 31, 2004

$
144.07

$
127.03

$
110.88December 31, 2005

$
246.15

$
182.51

$
116.33December 31, 2006

$
180.24

$
237.31

$
134.70December 31, 2007

$
58.60

$
333.59

$
142.10December 31, 2008

$
1.57

$
195.20

$
89.53


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Table of Contents

ITEM 6.    SELECTED FINANCIAL DATA

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

Year Ended December 31,2008

2007(1)

2006(2)(3)

2005(4)

2004(5)(in thousands, except per share amounts)Statement of operations:Total revenue

$
158,777

$
160,900

$
129,744

$
121,183

$
64,505Operating expenses:Oil and natural gas operating expenses including production and ad valorem taxes


26,576


30,196


18,257


17,068


9,309Depletion, depreciation, amortization and accretion


88,341


91,718


61,080


40,218


21,928Impairment of oil and natural gas properties(6)


362,851





96,942





General and administrative expenses


16,776


17,494


13,788


12,436


9,447Total operating expenses


494,544


139,408


190,067


69,722


40,684Operating income (loss)


(335,767
)

21,492


(60,323
)

51,461


23,821Interest expense and amortization of deferred loan costs, net of amounts capitalized


(13,190
)

(11,566
)

(2,665
)

(153
)

(473
)Other income


289


379


152


128


36Income (loss) before income taxes


(348,668
)

10,305


(62,836
)

51,436


23,384Income tax (expense) benefit


15,778


(3,733
)

21,575


(18,078
)

(8,255
)Net income (loss)


(332,890
)

6,572


(41,261
)

33,358


15,129Preferred stock dividends


(6,544
)

(7,577
)







Net income (loss) to common stockholders

$
(339,434
)
$
(1,005
)
$
(41,261
)
$
33,358

$
15,129Basic earnings (loss) per share

$
(11.89
)
$
(0.04
)
$
(2.38
)
$
1.95

$
1.16Diluted earnings (loss) per share

$
(11.89
)
$
(0.04
)
$
(2.38
)
$
1.87

$
1.11Basic weighted average number of common shares outstanding(1)(5)


28,682


27,613


17,368


17,122


13,029Diluted weighted average number of common shares outstanding(1)(5)


28,682


27,613


17,368


17,815


13,648EBITDA Reconciliation(7):Net income (loss)

$
(332,890
)
$
6,572

$
(41,261
)
$
33,358

$
15,129Income tax expense (benefit)


(15,778
)

3,733


(21,575
)

18,078


8,255Interest expense and amortization of deferred loan costs, net of amounts capitalized


13,190


11,566


2,665


153


473Interest income


(206
)

(379
)

(152
)

(128
)

(36
)Depletion, depreciation, amortization and accretion


88,341


91,718


61,080


40,218


21,928EBITDA

$
(247,343
)
$
113,210

$
757

$
91,679

$
45,749


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As of December 31,2008

2007(1)

2006(2)(3)

2005(4)

2004(5)(in thousands)Selected Cash Flow Data:Net cash provided by operating activities

$
82,735

$
122,869

$
97,409

$
93,111

$
42,270Net cash used in investing activities(1)

$
(52,157
)
$
(515,826
)
$
(140,412
)
$
(167,280
)
$
(89,410
)Net cash provided by (used in) financing activities(1)

$
(29,266
)
$
398,039

$
44,418

$
72,568

$
48,080Selected Balance Sheet Data:Working capital(8)

$
(203,281
)
$
2,262

$
10,162

$
10,537

$
8,957Property and equipment, net(5)


307,059


717,290


289,457


306,456


165,840Total assets


357,597


774,505


321,657


343,380


190,990Long-term debt, including current maturities(9)


239,000


260,000


129,000


85,000


20,000Stockholders' equity(1)(5)


97,488


434,776


156,052


191,755


150,467


---

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

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Table of Contents

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 a strategy which focused on a balanced program of exploration, exploitation and development and acquisition of oil and gas properties. In
late 2007, in an attempt to enhance shareholder value we began to assess our strategic alternatives and have subsequently expanded this process to include a further evaluation of both our financial
and strategic alternatives in late 2008 and continuing into 2009. Our current primary focus is on capital preservation and resolving the uncertainty and challenges we face.

We
generate revenues, income and cash flows by producing and marketing oil and natural gas produced from our oil and natural gas properties. We have historically made significant capital
expenditures in our exploration, development, and production activities that have allowed us to continue generating revenue, income and cash flows. In recent years, we have also spent considerable
efforts on acquisitions, including both corporate and asset acquisitions. We are currently operating with a reduced capital spending program as we continue to pursue the sale of some or all of our
assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company.

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



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OUTLOOK AND REVIEW OF FINANCIAL AND STRATEGIC ALTERNATIVES

On December 18, 2007, we announced the hiring of a financial advisor to assist our Board of Directors with an assessment of
strategic alternatives. On February 7, 2008, we provided an update on the strategic alternatives process and announced publicly that we would implement a process to explore a merger or sale of
the company. As a result of the strategic alternatives process, on July 14, 2008, we entered into an Agreement and Plan of Merger (the "Merger Agreement") with Chaparral Energy, Inc.
("Chaparral") and Chaparral Exploration, L.L.C., a Delaware limited liability company and wholly owned direct subsidiary of Chaparral ("Sub"), whereby we would merge with and into Sub. The
Merger Agreement was unanimously approved by our Board of Directors and Chaparral's Board of Directors and stockholders. To provide additional funding for the transaction, Chaparral expected to sell
1.5 million shares of its Series B convertible preferred stock, par value $0.01 per share for $150 million in a private sale to Magnetar Financial LLC, on behalf of itself
and one or more of its affiliates and assigns (collectively, "Magnetar"). On October 23, 2008, we adjourned our annual meeting of stockholders and announced our plans to reconvene the meeting
on December 4, 2008, when our common stockholders would vote on the adoption of the Merger Agreement. The adjournment to the later date was intended to allow additional time for Edge common
stockholders to receive and consider additional information regarding the proposed merger with Chaparral. On December 3, 2008, we announced that we would reconvene the annual meeting of
stockholders on December 29, 2008. The credit crisis and related turmoil in the global financial system and economic recession in the U.S. during the fourth quarter of 2008, along with declines
in commodity prices and our stock prices, created a challenging environment for the successful completion of our proposed merger with Chaparral. On December 17, 2008, we announced the
termination of the Merger Agreement after both we and Chaparral determined it was highly unlikely that the conditions to the closing of the proposed merger would be satisfied or that Chaparral would
be able to obtain sufficient debt and equity financing to allow them to complete the proposed merger and operate as a combined company, particularly in light of the challenging environment in the
financial markets and the energy industry. As a result, after consultation with our legal and financial advisors, our Board of Directors approved a merger termination agreement with Chaparral and a
termination and settlement agreement among us, Chaparral and Magnetar. Pursuant to the termination agreements, Magnetar reimbursed Chaparral $5.0 million for certain expenses, of which
$1.5 million was paid to us at Chaparral's direction, of which we paid $0.3 million to our then-financial advisor, Merrill Lynch.

We
are currently undertaking the evaluation and assessment of various financial and strategic alternatives, which may include the sale of some or all of our assets, a merger or other
business combination involving the Company, restructuring or recapitalization of the Company to address our liquidity issues and the Deficiency under our Revolving Facility (see discussion below). We
have retained an investment banking firm to assist further in the evaluation of our strategic and financial alternatives.

During
January 2009, we announced that the lenders ("Lenders") to our Fourth Amended and Restated Credit Agreement (as amended, the "Revolving Facility") had completed their borrowing
base redetermination and reduced our borrowing base to $125 million, resulting in a $114 million borrowing base deficiency (the "Deficiency"). Pursuant to the terms of the Revolving
Facility, we elected to prepay the Deficiency in six equal monthly installments, with the first $19 million installment being due on February 9, 2009. On February 9, 2009, we
entered into a Consent and Agreement (the "February Consent") among us and the Lenders, deferring the payment date of the first $19 million installment until March 10, 2009, and
extending the due date for each subsequent installment by one month with

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the
last of the six $19 million installment payments to be due on August 10, 2009. In connection with the February Consent, we agreed to prepay $5.0 million of our outstanding
advances under the Revolving Facility, in two equal installments. The first $2.5 million prepayment was paid on February 9, 2009 and the second $2.5 million prepayment was paid on
February 23, 2009. Each of the prepayments will be applied on a pro rata basis to reduce the remaining six $19 million deficiency payments. On March 10, 2009, we entered into a
Consent and Agreement (the "March Consent") with the Lenders under the Revolving Facility, which provided, among other things, for the extension of the due date for the first installment to repay the
Deficiency from March 10, 2009 to March 17, 2009. Notwithstanding such extension, we agreed with the Lenders that each of the other five equal installment payments required to eliminate
the Deficiency would be due and payable as provided for in the February Consent.

On
March 16, 2009, we entered into Consent and Amendment No. 4 to our Revolving Facility (the "Amended Consent") which provides, among other things, (1) that we will
make a $25 million payment on May 31, 2009 with all remaining principal, fees and interest amounts under our Revolving Facility to be due and payable on June 30, 2009,
(2) that it will be an event of default (i) if we fail to have executed and delivered on or before May 15, 2009 at least one of the following (a) a commitment letter from a
lender or group of lenders reasonably satisfactory to our Lenders providing for the provision by such lender or group of lenders of a credit facility in an amount sufficient to repay all of our
obligations under the Revolving Facility on or before June 30, 2009, (b) a merger agreement or similar agreement involving us as part of a transaction that results in the repayment of
our obligations under the Revolving Facility on or before June 30, 2009, and (c) a purchase and sale agreement with a buyer or group of buyers reasonably acceptable to our Lenders
providing for a sale transaction by us that results in the repayment of all of our obligations under the Revolving Facility on or before June 30, 2009, or (ii) if we are in default under
or our hedging arrangements have been terminated or cease to be effective without the prior written consent of our Lenders, (3) that our advances under the Revolving Facility will bear interest
at a rate equal to the greater of (a) the reference rate publicly announced by Union Bank of California, N.A. for such day, (b) the Federal Funds Rate in effect on such day plus
0.50% and (c) a rate determined by the Administrative Agent to be the Daily One-Month LIBOR (as defined in the Revolving Facility), in each case plus 2.5% or, during the
continuation of an event of default, plus 4.5% (resulting in an effective interest rate of approximately 5.75% as of March 16, 2009), (4) for limitations on the making of capital
expenditures and certain investments, and (5) for the elimination of the current ratio, leverage ratio and interest coverage ratio covenant requirements. The Amended Consent also eliminates the
six $19 million deficiency payments which were contemplated by the February Consent and the March Consent. To comply with the terms of the Amended Consent, we anticipate that we will need to
(i) sell select individual assets prior to May 31, 2009 to enable us to make the $25 million payment which is due on May 31, 2009, and/or (ii) negotiate a commitment
letter with a new lender or group of lenders prior to May 15, 2009 in an amount sufficient to repay all of our obligations under the Revolving Facility on or before June 30, 2009, and/or
(iii) have negotiated the sale, merger or other business combination involving us which
results in the repayment of all of our obligations under the Revolving Facility prior to May 15, 2009 and to have closed such transaction on or before June 30, 2009. The Amended Consent
limits the making of capital expenditures and we anticipate a severe curtailment of our drilling plans and other capital expenditures in 2009.

If
we breach any of the provisions of the Amended Consent or the Revolving Facilities, our Lenders will be entitled to declare an event of default, at which point the entire unpaid
principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, would become immediately due and payable. In any event, the entire unpaid
principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, will be payable on June 30, 2009 unless earlier paid or a further
extension with respect to payment is negotiated with our Lenders. Our Lenders may take action to enforce their rights with

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respect
to the outstanding obligations under the Revolving Facility. Because substantially all of our assets are pledged as collateral under the Revolving Facility, if our Lenders declare an event of
default, they would be entitled to foreclose on and take possession of our assets. In such an event, we may be forced to liquidate or to otherwise seek protection under Chapter 11 of the U.S.
Bankruptcy Code. These matters, as well as the other risk factors related to our liquidity and financial position raise substantial doubt as to our ability to continue as a going concern. See ITEM 7. "MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSLIQUIDITY AND CAPITAL
RESOURCESREVOLVING FACILITY."With respect to our compliance with the Amended Consent, there can be no assurance that we will be able to
further negotiate the terms of the Amended Consent or negotiate a further restructuring of the related indebtedness or that we will be able to make any required payments when they become due.
Moreover, there can be no assurance that we will be successful in our efforts to comply with the terms of the Amended Consent, including our ongoing efforts to evaluate and assess our various
financial and strategic alternatives (which may include the sale of some or all of our assets, a merger or other business combination involving the Company, or the restructuring or recapitalization of
the Company). If such efforts are not successful, we may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

Going ConcernIn addition to the Deficiency under our Revolving Facility, the capital expenditures required to maintain and/or grow production and
reserves are substantial. Our stock price has significantly declined over the past year which makes it more difficult to obtain equity financing on acceptable terms to address our liquidity issues. In
addition, we are reporting negative working capital at December 31, 2008 and a third consecutive year of net losses for the year ended December 31, 2008, which is largely the result of
impairments of our oil and natural gas properties. Therefore, there is substantial doubt as to our ability to continue as a going concern for a period longer than the current fiscal year. Our ability
to continue as a going concern is dependent upon the success of our financial and strategic alternatives process, which may include the sale of some or all of our assets, a merger or other business
combination involving the Company or the restructuring or recapitalization of the Company. Until the possible completion of the financial and strategic alternatives process, our future remains
uncertain and there can be no assurance that our efforts in this regard will be successful.

Our
consolidated financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which implies we will continue to meet
our obligations and continue our operations for the next twelve months. Realization values may be substantially different from carrying values as shown, and our consolidated financial statements do
not include any adjustments relating to the recoverability or classification of recorded asset amounts or the amount and classification of liabilities that might be necessary as a result of this
uncertainty. Our independent auditors have included an explanatory paragraph in their report on our consolidated financial statements that raises substantial doubt about our ability to continue as a
going concern. See ITEM 8."FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAReport of the Independent Registered Accounting Firm."

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

INDUSTRY AND ECONOMIC FACTORS

In managing our business, we must deal with many factors inherent to our industry. First and foremost is the fluctuation of oil and
natural gas prices. Our revenues, the value of our assets, our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in oil and
natural gas prices and the costs to produce our reserves. Oil and natural

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gas
prices are subject to significant fluctuations that are beyond our ability to control or predict without losing some advantage of the upside potential. In recent years, oil and natural gas
commodity prices have generally trended upwards in response to robust demand and constrained supplies, with oil and natural gas prices peaking at more than $140.00 per barrel and $13.00 per Mcf,
respectively, in July 2008. In the second half of 2008, a world-wide economic recession and oversupply of natural gas in North America led to an unprecedented decline in oil and natural
gas prices, with oil falling by more than $100.00 per barrel and natural gas falling more than $8.00 per Mcf from their peaks in July 2008.

Although
certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. Our costs and expenses tend to react
to activity levels in our industry and commodity price movements. In response to the recent historically high commodity prices, the oil and natural gas industry experienced significant increases in
activity and in demand for oil field services. The increased demand for these services resulted in significant inflation in both operating and capital costs. Although commodity prices have declined
significantly in recent
months, the inflated cost of oil field services resulting from recent historically high commodity prices did not decrease as rapidly. The prospect of continued low commodity prices and
disproportionately high service costs will constrain the industry's capital reinvestment for the near future.

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, oftentimes resulting in
no commercially productive reserves being discovered. These factors, together with increased demand for rigs, equipment, supplies and services, have made it difficult at times for us to further our
growth, and made timely execution of our planned activities difficult.

Our
business, as with other extractive businesses, is a depleting one in which each gas equivalent produced must be replaced or our asset base and capacity to generate revenues in the
future will shrink. This was a factor in our 2008 results, which reflected a 24% lower proved reserve base at year-end. We were unable to replace the production we generated due to our
reduced capital spending program and higher drilling and operating costs. This will continue to be a factor in 2009 as we operate under a severely limited capital and operating budget.

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

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

The
growing global economic crisis created an environment of uncertainty during the third and fourth quarters of 2008. We are unable to predict the impact on our business of a continued
decline in commodity prices and the global economy. Possible negative impacts, among others, could include further declines in our revenue, cash flows and liquidity.

APPROACH TO THE BUSINESS

Historically, our goal has been to fund ongoing exploration and development projects with cash flow provided by operating activities,
occasionally supplemented with external sources of capital. As a result of the strategic alternatives process that began in late 2007 (see discussion above), our Board

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approved
a reduced capital expenditure budget for 2008, while we assessed the potential sale or merger of the Company. This affected our spending in the third and fourth quarters of 2008.

More
recently, in connection with our ongoing financial and strategic alternatives process and our liquidity issues resulting from the Deficiency under our Revolving Facility and the
related Amended Consent, we have operated and will continue to operate with a severely limited capital spending program in 2009 as we continue to pursue the sale of some or all of our assets, a merger
or other business combination involving the Company or the restructuring or recapitalization of the Company. Our strategy is currently to continue under a severely limited capital and operating
budget, thereby reducing our normal exploration and development activities as we seek to preserve liquidity and resolve the uncertainty and challenges that we face as we pursue various financial and
strategic alternatives.

We
normally hedge our exposure to volatile oil and natural gas prices on a portion of our expected production to reduce price risk. As a result of changes to our forecasted 2008
production and the impact of certain asset divestitures, both of which reduced production as compared to that expected at the time we entered into the derivative contracts, we had approximately 115%
and 190% of our 2008 natural gas and crude oil production, respectively, covered by derivative contracts. This overhedged position exposed us to greater risk of commodity price increases because at
times we did not have the physical production cash inflows to offset the losses incurred on the portion of the contracts that were overhedged. During September and October 2008, we entered into two
new contracts for certain fourth quarter 2008 production that were intended to offset a portion of the volumes that were overhedged and thereby reduce our exposure to significant increases in natural
gas and crude oil prices.

ACQUISITIONS AND DIVESTITURES

AcquisitionsWe became increasingly active in acquisitions in recent years. In the past, we have looked to acquisitions to enable us to achieve our
growth objectives. Acquisitions add meaningful incremental increases in reserves and production and may range in size from acquiring a working interest in non-operated producing property
to an entire field or company. Unlike drilling capital, which is planned and budgeted, acquisition capital is neither budgeted nor allocated. Specific timing and size of acquisitions cannot be
predicted, but in light of current conditions, we do not expect to make any acquisitions in the coming year.

January 2007 AcquisitionDuring the first quarter of 2007, we completed the largest acquisition in our history. We acquired oil and natural gas
properties located in 13 counties in south and southeast Texas, exploration rights, leasehold acreage, gathering facilities and gathering pipelines from a privately held company (the "January 2007
Acquisition"). This acquisition had a substantial impact on our reserves, production revenues, operating costs, and property base. The final adjusted cash purchase price was $384.4 million. We
financed the purchase price of the January 2007 Acquisition through public offerings of common and preferred stock (see Notes 13 and 14 to our consolidated financial statements) and borrowings
under our Revolving Facility (see Note 11 to our consolidated financial statements). We also capitalized approximately $1.4 million in other direct costs resulting from the acquisition
and assumed asset retirement obligation ("ARO") liabilities of $0.9 million.

As
part of this acquisition, we also acquired a 12.5% working interest in an approximate 160 square mile 3-D exploration area with approximately 55,000 gross acres of leases
and options located in the Yates Ranch/Hostetter project area in McMullen and Duval Counties in south Texas. During the third quarter 2007, we elected to terminate this exploration venture. The
effective date of termination for this venture was October 2, 2007. In exchange for returning all 3-D seismic data covering the area of mutual interest, the privately held company
refunded our payments since January 2007 related to this exploration venture. In October 2007, we received $5.5 million, including the $5.0 million initial price paid for the venture and
$0.5 million in expenses related to the venture, which were incurred and paid to the privately held company from January to September 2007.

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

DivestituresWe regularly review our asset base for the purpose of identifying non-core assets, the disposition of which would increase
capital resources available for other activities and create organizational and operational efficiencies. While in the past we have not generally disposed of assets solely for the purpose of reducing
debt, in connection with our ongoing financial and strategic alternatives process, we are actively pursuing the possible sale of some or all of our assets or other business combinations involving the
Company. We believe that we will need to make significant divestitures in 2009 in order to comply with the terms of the Amended Consent. During 2008, we completed sales of a pipeline and certain
working interests in approximately 120 properties located in Texas and Mississippi to various buyers for aggregate proceeds of approximately $19.2 million, which we used to reduce outstanding
debt. During January 2007, we divested a portion of our interest in a Louisiana well for $1.1 million. During 2006, we sold our Buckeye properties in Live Oak County, Texas for
$0.6 million.

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 consolidated financial statements. Changes in these estimates and assumptions could materially affect our financial position, results of operations or cash flows. Management considers an
accounting estimate to be critical if:



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

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

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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 natural gas properties requires a quarterly calculation of a limitation on
capitalized costs, often referred to as a full-cost ceiling test. The ceiling is the discounted present value of our estimated total proved reserves (using a 10% discount rate) adjusted
for taxes and the impact of cash flow hedges on pricing, if cash flow hedge accounting is applied. The ceiling test calculation dictates that prices and costs in effect as of the last day of the
period are to be used in calculating the discounted present value of our estimated total proved reserves. However, if prices increase subsequent to the balance sheet date but before the filing date,
SEC guidelines allow a registrant to elect to use the subsequent date's higher prices in calculating the full-cost ceiling. We made this election for the third and fourth quarters of 2007.
To the extent that our capitalized costs (net of accumulated depletion, impairments and deferred taxes) exceed the ceiling, the excess must be written off to expense. Once incurred, this impairment of
oil and natural gas properties is not reversible at a later date even if oil and natural gas prices increase. A ceiling test impairment could result in a significant loss for a reporting period;
however, future depletion expense would be correspondingly reduced. Our estimated proved reserves volumes have decreased during the period from year-end 2007 to 2008, and the average
oil, NGL and natural gas prices at the balance sheet date as of December 31, 2008 were also lower at $44.60 per barrel, $26.76 per barrel and $5.71 per MMBtu, respectively. As a result, we
recorded a ceiling test impairment during the three months ended December 31, 2008 of $233.3 million ($215.8 million, net of tax). This impairment, along with the impairment
recorded during the third quarter of 2008 of $129.5 million ($84.2 million, net of tax), will significantly affect the comparability of results between the 2008 and 2007 periods. During
the year ended December 31, 2007, we elected to use subsequent pricing as of January 20, 2008 of $90.57 per barrel of oil and $8.42 per MMBtu. As a result, no ceiling test impairment was
required at December 31, 2007. During the year ended December 31, 2006, we recorded a ceiling test impairment of $96.9 million ($63.0 million, net of tax).

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%.

"Ceiling" TestFactors that contribute to a ceiling test impairment include the price used to calculate the reserve limitation threshold and reserve
quantities. A significant reduction in prices at a measurement date could trigger a full-cost ceiling impairment. We recorded an impairment of $233.3 million ($215.8 million,
net of tax) at December 31, 2008. A 10% increase or decrease in prices would have decreased or increased our impairment by approximately 20%, net of tax, respectively. Although our hedging
program is intended to mitigate the economic impact of any significant price decline, it did not impact our ceiling test at December 31, 2008 because we do not apply cash flow hedge accounting
to our derivative contracts. Had we applied cash flow hedge accounting to our outstanding derivative contracts, there would have been an 8% decrease in the impairment taken as a result of the low
prices at the measurement date falling below the price floors. A 10% increase or decrease in reserve volume would have decreased or increased the impairment calculated at December 31, 2008 by
approximately 10%. Should commodity prices continue to decrease in 2009 or we further revise our reserve quantities, the potential for additional ceiling test impairments at a future date exists.

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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 natural gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells.

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

Estimating
the future asset removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future, and
contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety
and public relations considerations. Inherent in the estimate of the present value calculation of our AROs are numerous assumptions and judgments including the ultimate settlement amounts, inflation
factors, credit-adjusted-risk-free-rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments.

Assumptions/Approach 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
period-end reserve reports prepared 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 have developed a standard cost estimate based on historical costs, industry quotes and depth of wells. This cost estimate is reviewed annually to determine
whether it is a reasonable estimate in the current environment. 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.

Effect if different assumptions used:We expect to see our calculations for new properties and revisions to existing properties impacted
significantly if interest rates rise, as the credit-adjusted-risk-free rate is one of the variables used on a quarterly basis. We also expect that significant changes to the
cost of retiring assets or the reserve life of our assets would have significant impact on our estimated ARO.

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Nature of Critical Estimate Item:Income TaxesIn accordance with SFAS No. 109,Accounting
for
Income Taxes,we have recorded a deferred tax asset and liability to account for the expected future tax benefits and consequences, respectively, of events that have been
recognized in our consolidated financial statements and our tax returns. There are several items that result in deferred tax asset and

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liabilities
on the balance sheet, the largest of which are deferred liabilities attributable to book basis in excess of tax basis in oil and natural gas properties and the impact of net operating loss
("NOL") carryforwards. We routinely assess our ability to use all of our NOL carryforwards that resulted from substantial income tax deductions, prior year losses and acquisitions. We consider future
taxable income in making such assessments. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, it is
reduced by a valuation allowance to remove the benefit of those NOL carryforwards from our consolidated financial statements. Additionally, in accordance with Financial Accounting Standards Board
("FASB") Interpretation 48,Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109("FIN 48"), we have
recorded a liability of $0.1 million associated with uncertain tax positions. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition
and measurement of a tax position taken or expected to be taken in a tax return. We are required to determine whether it is more likely than not (a likelihood of more than 50 percent) that a
tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position in order to record any financial
statement benefit. If that step is satisfied, then we must measure the tax position to determine the amount of benefit to recognize in our consolidated financial statements. The tax position is
measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.

Assumptions/Approach Used:Numerous judgments and assumptions are inherent in the determination of future taxable income and tax return
filing
positions that we take, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices).

Effect if Different Assumptions Used:Along with consultation from an independent public accounting firm used in tax consultation, we
continually
evaluate complicated tax law requirements and their effect on our current and future tax liability and our tax filing positions. Despite our attempt to make an accurate estimate, the ultimate
utilization of our NOL carryforwards is highly dependent upon our actual production, the realization of taxable income in future periods, Internal Revenue Code Section 382 limitations, and
potential tax elections. If we estimate that some or all of our NOL carryforwards are more likely than not going to expire or otherwise not be utilized to reduce future tax, we would be required to
record a valuation allowance to remove the benefit of those NOL carryforwards from our consolidated financial statements, as was done in the fourth quarter of 2008. Our liability for uncertain tax
positions is dependent upon our judgment on the amount of financial statement benefit that an uncertain tax position will realize upon ultimate settlement and on the probabilities of the outcomes that
could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of financial
statement benefit. To the extent that a valuation allowance or uncertain tax position is established or increased or decreased during a period, we may be required to include an expense or benefit
within tax expense in the statement of operations. During the fourth quarter of 2008, we recorded a valuation allowance of approximately $110 million as a result of our anticipated inability to
utilize all of our deferred tax assets.

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Nature of Critical Estimate Item:Derivative and Hedging ActivitiesDue to the instability of oil and natural gas
prices, from
time to time, we may enter into price-risk management transactions (e.g., swaps, collars and floors) related to our expected oil and natural gas production to seek to achieve a more
predictable cash flow, as well as to reduce exposure from commodity price fluctuations. While these transactions are intended to be economic hedges of price risk, different accounting treatment may
apply depending on if they qualify for cash flow hedge accounting. In accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities (as
amended),all derivatives,

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other
than those that meet the normal purchases and sales exception, are recorded on the balance sheet at fair value. SeeITEMS 1 AND 2. "BUSINESS AND
PROPERTIESDERIVATIVES."

Cash Flow Hedge AccountingFor transactions accounted for under cash flow hedge accounting treatment, the effective portion of the change in fair
value of outstanding derivative contracts is deferred through other comprehensive income ("OCI") on the balance sheet, rather than recorded immediately in total revenue on the statement of operations.
Ineffective portions of the changes in the fair value of the derivative contracts are recognized in revenue as they occur. While the hedge contract is outstanding, the fair value may increase or
decrease until settlement of the contract. The cash flows resulting from settlement of derivative transactions which relate to economically hedging our physical production volumes are classified in
operating activities on the statement of cash flows, and the cash flows resulting from settlement of derivative transactions considered "overhedged" positions are classified in investing activities on
the statement of cash flows.

Mark-to-Market AccountingFor transactions accounted for using mark-to-market accounting treatment,
until the contract settles, the entire change in the fair value of the outstanding derivative contract is recorded in total revenue immediately, and not deferred through OCI, and there is no
measurement of effectiveness. Since January 1, 2006, we have applied mark-to-market accounting treatment to all outstanding derivative contracts.

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. It also approximates the fair value of the contracts as that would be the cost to us to terminate a contract at
that point in time, as well as the potential inflows or outflows of cash for the expiration of the contracts. Due to the fact that we apply mark-to-market accounting treatment,
the offset to the balance sheet asset or liability, or the change in fair value of the contracts, is included in revenue on the statement of operations rather than in OCI on the balance sheet.

Effect if different assumptions used:At December 31, 2008, a 10% change in the commodity price per unit would cause the fair value
total of
our derivative financial instruments to increase or decrease by approximately $1.5 million. Had we applied cash flow hedge accounting treatment to all of our derivative contracts outstanding at
December 31, 2008, our net loss to common stockholders for the year would have been $236.2 million, or $8.30 per basic and diluted loss per share, assuming that all hedges were fully
effective, as compared to our reported net loss to common stockholders for the year ended December 31, 2008 of $339.4 million, or $11.89 basic and diluted loss per share.

RESULTS OF OPERATIONS

This section includes discussion of our 2008, 2007 and 2006 results of operations. We are an independent oil and natural gas company
engaged in the exploration, development, acquisition and production of crude oil and natural gas properties in the United States. Our resources and assets are managed and our results reported as one
operating segment. We conduct our operations primarily along the onshore United States Gulf Coast, with our primary emphasis in Texas, Mississippi, New Mexico and Louisiana.

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Revenue and Production

Our primary source of production and revenue is natural gas. For the years ended December 31, 2008, 2007 and 2006, our product
mix contributed the following percentages of revenues and production:

REVENUES(1)

REVENUES(2)2008

2007

2006

2008

2007

2006Natural gas


65
%

74
%

79
%

64
%

67
%

77
%Natural gas liquids


17
%

16
%

4
%

17
%

14
%

5
%Crude oil


18
%

10
%

17
%

19
%

19
%

18
%Total


100
%

100
%

100
%

100
%

100
%

100
%


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PRODUCTION VOLUMES (MCFE)2008

2007

2006Natural gas


70
%

73
%

80
%Natural gas liquids


20
%

16
%

8
%Crude oil


10
%

11
%

12
%Total


100
%

100
%

100
%


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

For the Year Ended December 31,

% Increase
(Decrease)2008

2007

2006

08 vs.
07

07 vs.
06(in thousands, except prices and percentages)Production Volumes:Natural gas (MMcf)


12,059


17,536


13,850


(31
)%

27
%Natural gas liquids (MBbls)


559


637


222


(12
)%

*Oil and condensate (MBbls)


294


460


345


(36
)%

33
%Natural gas equivalent (MMcfe)


17,176


24,118


17,251


(29
)%

40
%Average Sales Price(1):Natural gas ($ per Mcf)(2)

$
8.51

$
6.66

$
6.68


28
%

*Natural gas liquids ($ per Bbl)


48.83


40.00


25.52


22
%

57
%Oil and condensate ($ per Bbl)(2)


101.66


70.86


63.10


43
%

12
%Natural gas equivalent ($ per Mcfe)(3)


9.24


6.67


7.52


39
%

(11
)%Revenue:Natural gas(2)

$
102,618

$
116,777

$
92,582


(12
)%

26
%Natural gas liquids


27,303


25,489


5,665


7
%

*Oil and condensate(2)


29,833


32,572


21,767


(8
)%

50
%Gain (loss) on derivatives


(977
)

(13,938
)

9,730


(93
)%

*Total revenue(3)

$
158,777

$
160,900

$
129,744


(1
)%

24
%


---

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ProductionFor the year ended December 31, 2008, production volumes decreased as compared to the same 2007 period primarily due to normal
production declines, asset sales completed during early 2008 and decreased capital re-investment in replacing production as compared to historical levels. To a lesser extent, Hurricane Ike
struck in mid-September 2008, causing some wells to be shut-in during the third and fourth quarters of 2008 resulting in additional production declines for all commodities. The
growth in natural gas production in 2007 was primarily due to the addition of new assets acquired in the January 2007 Acquisition and to a lesser extent the additional assets acquired in the Chapman
Ranch Field in December of 2006. Additionally, new wells drilled during 2007 in the Vicksburg and Deep Frio project areas of Texas and in southeast New Mexico contributed to the growth. Partially
offsetting these increases were declines in Mississippi, some of our Queen City and Lobo properties in Texas, and on older wells in the southeast New Mexico project area. Additionally, in late 2006
and early 2007, we entered into natural gas processing agreements for our Chapman Ranch production and our non-operated Queen City production in Jim Hogg County, which agreements
contributed a portion of the increase in NGL production in 2007 as compared to 2006. The following summarizes our average daily production volumes:

For the Year Ended December 31,2008

2007

2006Production Volumes per Day:Natural gas (MMcf/D)


32.9


48.0


37.9Natural gas liquids (MBbls/D)


1.5


1.7


0.6Oil and condensate (MBbls/D)


0.8


1.3


0.9Natural gas equivalent (MMcfe/D)


46.9


66.1


47.3


Average sales priceOur sales revenue is sensitive to the changes in prices received for our products. A substantial portion of our production is
sold
at prevailing market prices, which fluctuate in response to many factors that are outside of our control. Imbalances in the supply and demand for oil and natural gas can have a dramatic effect on the
prices we receive for our production. Political instability and availability of alternative fuels could impact worldwide supply, while the economy, weather and other factors outside of our control
could impact demand. Although commodity prices were very high during the second and third quarters of 2008, prices in the fourth quarter of 2008 decreased significantly, which lead to unrealized gains
in our year-end derivative valuations and the ceiling test impairment (see discussions below).

Natural gas revenueThe overall decrease in production for 2008 compared to 2007 resulted in an decrease in revenue of approximately
$36.5 million (based on 2007 comparable period pre-derivative prices). Excluding the effect of derivative activity, the average natural gas sales price for production in 2008 was
higher than 2007, which resulted in increased revenue of approximately $22.3 million (based on 2008 production). The overall increase in production for 2007 compared to 2006 resulted in an
increase in revenue of approximately $24.6 million (based on 2006 comparable period pre-derivative prices). Average prices received in 2007 were slightly lower than 2006, resulting
in decreased revenue of approximately $0.4 million (based on 2007 production). See below for a discussion of the impact of natural gas derivatives on prices and revenue.

NGL revenueThe overall decrease in production for 2008 compared to 2007 resulted in an decrease in revenue of approximately $3.1 million
(based on 2007 comparable period prices). The

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average
NGL sales price for production in 2008 was higher than 2007, which resulted in increased revenue of approximately $4.9 million (based on 2008 production). The overall increase in
production for 2007 compared to 2006 resulted in an increase in revenue of approximately $10.6 million (based on 2006 comparable period prices). Average prices received in 2007 were 57% higher
than 2006, resulting in increased revenue of approximately $9.2 million (based on 2007 production). We have not placed derivative transactions on our NGL production in the past.

Crude oil and condensate revenueThe overall decrease in production for 2008 compared to 2007 resulted in a decrease in revenue of approximately
$11.7 million (based on 2007 comparable period pre-derivative prices). Excluding the effect of derivative activity, the average crude oil and condensate sales price for production
in 2008 was higher than 2007, which resulted in increased revenue of approximately $9.0 million (based on 2008 production). The overall increase in production for 2007 compared to 2006 resulted
in an increase in revenue of approximately $7.2 million (based on 2006 comparable period pre-derivative prices). Average prices received in 2007 were 12% higher than 2006, resulting
in increased revenue of approximately $3.6 million (based on 2007 production). See below for a discussion of the impact of crude oil derivatives on prices and revenue.

DerivativesThe volume and price contract terms of our derivative contracts vary from period to period and therefore interact differently with the
changing pricing environment, which makes the comparability of the results for each period difficult. In all periods presented, we applied mark-to-market accounting treatment
to our derivative contracts; therefore the full volatility of the non-cash change in fair value of our outstanding contracts is reflected in total revenue and will continue to affect total
revenue until outstanding contracts expire. Since these gains/losses are not a function of the operating performance of our oil and natural gas assets, excluding their impact from the above
discussions helps isolate the operating performance of those assets. The following table

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

Year Ended December 31,2008

2007

2006(in thousands, except prices)$

$ per unit(1)

$

$ per unit(1)

$

$ per unit(1)Natural gas contract settlements (Mcf)

$
(9,453
)
$
(0.78
)
$
4,513

$
0.26

$
4,699

$
0.34Crude oil contract settlements (Bbl)


(19,259
)

(65.63
)

(935
)

(2.03
)




Mark-to-market reversal of prior period unrealized change in fair value of natural gas derivative contracts (Mcf)


(2,626
)

(0.22
)

(4,686
)

(0.27
)




Mark-to-market unrealized change in fair value of natural gas derivative contracts (Mcf)


13,390


1.11


2,626


0.15


4,686


0.34Mark-to-market reversal of prior period unrealized change in fair value of crude oil derivative contracts (Bbl)


14,956


50.96


(500
)

(1.09
)

(155
)

(0.45
)Mark-to-market unrealized change in fair value of crude oil derivative contracts (Bbl)


2,015


6.87


(14,956
)

(32.53
)

500


1.45Gain (loss) on derivatives (Mcfe)

$
(977
)
$
(0.06
)
$
(13,938
)
$
(0.58
)
$
9,730

$
0.56


---

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 cap 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 overall 2008 derivative position exceeded our total 2008 production, due to changes in forecasted production and certain asset divestitures. Although we took
steps in the fourth quarter of 2008 to reduce the overhedge exposure, the position exposed us to greater losses during those periods of high prices in the second and third quarters of 2008. For
additional discussion of the overhedge position, see Note 9 to our consolidated financial statements.

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Costs and Operating Expenses

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

% Increase
(Decrease)For the Year Ended December 31,08 vs.
07

07 vs.
062008

2007

2006(in thousands, except percentages)Oil and natural gas operating expenses

$
16,889

$
17,078

$
9,122


(1
)%

87
%Severance and ad valorem taxes


9,687


13,118


9,135


(26
)%

44
%Depreciation, depletion, amortization and accretion:Oil and natural gas property and equipment


87,223


90,826


60,472


(4
)%

50
%Other assets


739


595


419


24
%

42
%ARO accretion


379


297


189


28
%

57
%Impairment of oil and natural gas properties


362,851





96,942


*


*General and administrative expenses


16,776


17,494


13,788


(4
)%

27
%Total operating expenses

$
494,544

$
139,408

$
190,067


*


(27
)%Other expense, net

$
12,901

$
11,187

$
2,513


15
%

*Income tax expense (benefit)


(15,778
)

3,733


(21,575
)

*


*Preferred stock dividends


6,544


7,577





(14
)%

*


---

Oil and natural gas operating expensesOil and natural gas operating expenses include direct operating costs, delivery commitment fees, repairs
and
maintenance and workover expenses. In 2008 these expenses were slightly lower than 2007 due to the sale of certain non-core assets during early 2008. Partially offsetting the decrease from
sold properties were increases in costs at Chapman Ranch, Flores/Bloomberg and Encinitas fields and a portion of the liability we recorded on our delivery commitment to Frontier in the amount of
$0.7 million (see Note 2 to our consolidated financial statements). In 2007, oil and natural gas operating expenses were significantly impacted by the January 2007 Acquisition, which
contributed 70% of the increase in costs (averaging $0.58 per Mcfe for the year) from 2006 to 2007. The increasing cost structure in 2007 as compared to 2006 resulted from added costs for compression,
expensed workovers and salt-water disposal as well as inflation in our industry. The increase in expenses was also affected to a lesser extent by the Chapman Ranch acquisition in December
of 2006. Operating expenses averaged $0.98 per Mcfe, $0.71 per Mcfe and $0.53 per Mcfe for the years ended December 31, 2008, 2007 and 2006, respectively.

Severance and ad valorem taxesSeverance taxes are levied directly on our non-hedge revenue dollars, therefore swings in revenues will
impact our severance tax expense. The severance tax rate realized in the years ended December 31, 2008, 2007 and 2006 was 5.6%, 4.8% and 5.4%, respectively. We recorded severance tax abatements
related to prior year periods during early 2007, which effectively lowered the 2007 rate realized and total expense. The rate realized also changes as a result of the changing mix of our production
locations. Ad valorem tax expense for 2008 was 85% lower than the prior year because we reduced our estimates in 2008 as a result of the actual 2007 costs coming in lower than originally anticipated
in 2007 accrual estimates. In addition, the 2008 ad valorem tax valuations, which are based on reserves, were lower in 2008 than in the prior year which resulted in lower costs for 2008. Ad valorem
costs increased in 2007 as compared to 2006 due to the addition of properties acquired in January 2007. If not for the January 2007 Acquisition, ad valorem tax expense for the year ended
December 31, 2007 would have decreased by approximately 50% as compared to the year ended December 31, 2006. On an equivalent basis, severance and ad valorem taxes averaged

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$0.56
per Mcfe, $0.54 per Mcfe and $0.53 per Mcfe for the years ended December 31, 2008, 2007 and 2006, respectively.

Depletion, depreciation and amortization ("DD&A") and accretion expenseDepletion expense on a unit of production basis for the years ended
December 31, 2008, 2007 and 2006 was $5.08 per Mcfe, $3.77 per Mcfe and $3.51 per Mcfe, respectively. The depletion rate has increased in recent
years due to significant property costs for both drilling and exploration activities, as well as our acquisition program, without a corresponding increase in reserves. Additionally, negative revisions
to our proved reserves at year-end 2007 increased our depletion rate. We expect the substantial impairments taken in 2008 to reduce our 2009 depletion rate.

Depreciation
expense of other assets is related to our executive office leasehold improvements, furniture and fixtures, computer equipment and software and pipelines that transport
third-party gas. Depreciation expense related to other assets increased from 2007 to 2008 due to our office expansion that occurred in the latter half of 2007, which included leasehold improvements,
new office furniture and equipment and computers and software. Depreciation expense increased from 2006 to 2007 primarily because of pipelines acquired in the January 2007 Acquisition.

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

Impairment of oil and natural gas propertiesAt December 31 and September 30, 2008 we recorded non-cash
full-cost ceiling test impairments of oil and natural gas properties in the amount of $233.3 million ($215.8 million net of tax) and $129.5 million
($84.2 million net of tax), respectively, as discussed in Note 2 to the consolidated financial statements. These write-downs were the result of declines in commodity prices and negative
revisions in our proved reserve quantities at year-end 2007 and during 2008. We recorded a non-cash full-cost ceiling test impairment of oil and natural gas
properties in the amount of $96.9 million ($63.0 million, net of tax) during 2006 as a result of declines in natural gas prices at September 30, 2006. No such impairment was
recorded in 2007.

General and administrative ("G&A") expensesIn 2008, we recorded costs associated with the strategic alternatives process, the proposed merger
with
Chaparral and the retention bonus program adopted during the second quarter of 2008. We incurred costs of approximately $2.5 million related to the strategic alternatives process and proposed
merger with Chaparral and approximately $2.8 million of retention bonuses. Other increases in total G&A expense for 2008 as compared to 2007 included health insurance, rent expense, and
maintenance contracts. Partially offsetting these increases were decreases in entertainment costs, Board compensation, professional fees such as audit and legal unrelated to the strategic alternatives
process, and bad debt expense. We also received a $1.5 million settlement from Magnetar for the termination of the proposed merger with Chaparral (see "Outlook and Review of Financial and
Strategic Alternatives") of which we paid $0.3 million to our then-financial advisor, Merrill Lynch. Our salary and benefits comprise approximately 80% of total G&A expense in each
year and therefore salary and benefits typically drive increases and decreases. In 2008, our salary and benefits costs decreased in comparison to 2007 as a result of the departure of several
employees. In 2007, we added 21 new employees and seven during 2006 as a result of our growth, which caused an overall increase in salary and personnel related costs for 2007 as compared to 2006.
Other cost increases during 2007 include rent expense for our corporate office expansion and professional service fees, offset by decreased costs for our Board of Directors and franchise taxes.
Franchise taxes in 2006 were higher than the subsequent years as a result of payment of a franchise tax settlement to the State of Texas of approximately $0.2 million. Also in 2006 we recorded
a litigation settlement of $0.2 million that was not repeated in the subsequent periods presented here. In general,

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G&A
expense is reduced by capitalized G&A and overhead reimbursement fees, both of which increased in each year. We capitalized $4.1 million, $4.0 million and $3.0 million of G&A
costs in 2008, 2007 and 2006, respectively. For the years ended December 31, 2008, 2007 and 2006, overhead reimbursement fees reduced G&A expense by approximately $1.4 million,
$1.2 million, and $0.4 million, respectively. G&A expenses, excluding non-cash share-based compensation costs, on a unit of production basis for the years ended
December 31, 2008, 2007 and 2006 were $0.89 per Mcfe, $0.60 per Mcfe and $0.68 per Mcfe, respectively.

A
portion of G&A expense is attributable to share-based compensation costs related to restricted stock awards granted in the past. Restricted stock awards vest over a three to four year
period. For the years ended December 31, 2008, 2007 and 2006 we recorded $1.6 million, $3.0 million and $2.0 million. The increase in compensation for restricted stock
awards in 2007 as compared to 2006 is related to additional restricted stock awards granted in conjunction with our increase in employees from 2006 to 2007. A large portion of the decrease in 2008 was
due to forfeitures of these grants by departing employees.

During
2008, we recorded bad debt expense of $0.1 million related to trade and joint interest accounts receivable that we felt were uncollectible. During 2007, we recorded bad
debt expense of $0.5 million related to the ongoing Golden Prairie/Duke dispute that we no longer felt we could collect as we exhausted our legal efforts on this matter. This was partially
offset by a reduction of bad debt expense of $0.3 million for a receivable that was reserved as uncollectible in 2001, but recovered during the fourth quarter of 2007. There was no bad debt
expense recorded in 2006. Historically we have not
experienced significant credit losses on our receivables, but we cannot ensure that similar such losses may not be realized in the future.

Upon
adoption of SFAS No. 123(R), as discussed in Notes 2 and 19 to our consolidated financial statements, during 2006, we recorded $68,937 in compensation expense for
stock options that had not vested as of adoption of SFAS No. 123(R). Those options have since vested and we have not issued new options since 2004. Therefore, we did not record any stock option
expense in 2008 and 2007 nor do we expect to record expense related to stock options in the near future.

Other income (expense)At December 31, 2008, 2007 and 2006 our unproved property balance was $16.4 million, $34.9 million, and
$57.6 million, respectively, which provided for capitalization of a portion of our gross interest costs. We incurred higher gross interest costs for the years ended December 31, 2008 and
2007 than for 2006 due to higher commitment fees on our Revolving Facility and higher outstanding debt balances. The year ended December 31, 2007 also includes a one time commitment fee of
$1.3 million paid to our lender for our unused bridge loan facility in January 2007 (see Note 11 to our consolidated financial statements). The year ended December 31, 2006 also
includes interest paid on our franchise tax settlement in 2006 of approximately $40,150. Interest costs on the franchise tax settlement were not subject to capitalization. The table below details our
interest expense, capitalized interest and weighted average debt for each of the periods indicated:

For the Year Ended December 31,2008

2007

2006(in thousands)Gross interest

$
14,396

$
18,471

$
7,761Less: capitalized interest


(2,609
)

(7,882
)

(5,261
)Interest expense, net

$
11,787

$
10,589

$
2,500Weighted Average Debt

$
244,858

$
229,597

$
102,077


Included
in other income (expense) is amortization of deferred loan costs of $1.4 million and $1.0 million associated with our Revolving Facility for the years ended
December 31, 2008 and 2007,

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respectively,
and $0.2 million associated with our then-existing credit facility for the year ended December 31, 2006. These costs were higher in 2008 and 2007 due to the
higher costs associated with our Revolving Facility compared to our prior credit facility. During 2008, we also wrote off approximately 25% of the remaining costs in relation to the decrease in the
borrowing base.

Also
included in other income (expense) was interest income, which totaled $0.2 million, $0.4 million, and $0.2 million for the years ended December 31, 2008,
2007 and 2006, respectively. The interest is earned on daily cash invested in overnight money market funds. We had increased cash on hand in 2007 providing for the increased interest income.

Income tax expense (benefit)We are subject to state and federal income taxes, but we are not in a federal income tax paying position as a result
of
deducting intangible drilling costs ("IDC") that reduce our taxable income for income tax purposes and NOL carryforwards that offset any remaining taxable income. A deferred income tax benefit of
$15.8 million and $21.6 million were recorded for the years ended December 31, 2008 and 2006, respectively. A deferred income tax provision of $3.7 million was recorded for
the year ended December 31, 2007. Due to valuation allowances and changes in amounts of permanent tax differences, including meals and entertainment and other expenses, our effective tax rate
also changes from time to time. The effective rate for 2008 was 4.5% due primarily to a deferred tax valuation allowance of approximately $110.2 million recorded in the fourth quarter of 2008.
The effective rate was 36.2% in 2007 and 34.3% in 2006. We were required to make alternative minimum tax payments of $94,100 for the year ended December 31, 2006 only.

Preferred stock dividendsOur Board of Directors declared quarterly dividends on our 5.75% Series A cumulative convertible perpetual
preferred
stock (the Convertible Preferred Stock") in 2007 and 2008. Our Board of Directors elected not to declare or make payments of the 2008 fourth quarter dividend on the outstanding Convertible Preferred
Stock because of our current liquidity situation (see "Liquidity and Capital Resources" section below). As of December 31, 2008, preferred dividends in arrears amounted to $1.7 million,
or $0.60 per share, on the Convertible Preferred Stock. The Convertible Preferred Stock was issued in connection with a public offering in January 2007, therefore no comparable dividends were paid in
2006.

Loss per shareFor the years ended December 31, 2008, 2007 and 2006, we reported a net loss to common shareholders and thus a loss per share.
Basic weighted average shares outstanding increased from approximately 17.4 million at December 31, 2006 to 27.6 million at December 31, 2007 and to 28.7 million at
December 31, 2008. There were minimal increases due to options exercised and vesting of restricted stock during each of these periods, but the primary cause of the significant increase from
2006 to 2007 was the public offerings of common stock and preferred stock in January 2007 that was made to partially finance the January 2007 Acquisition. We issued approximately 10.9 million
shares of common stock. We also issued approximately 2.9 million shares of the Convertible Preferred Stock, which, when converted, have an anti-dilutive effect of approximately
8.7 million shares of common stock, and therefore, are not included in the calculation of diluted earnings per share for the year ended December 31, 2007 and 2008. Diluted earnings per
share calculations in loss periods do not include certain shares that would result in an anti-dilutive effect on earnings per share.

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LIQUIDITY AND CAPITAL RESOURCES

Historically, our primary ongoing source of capital was the cash flow generated from our operating activities supplemented by
borrowings under our Revolving Facility. We currently do not have any available borrowing capacity under our Revolving Facility (see "Revolving Facility" below for additional discussion) and we have a
$25 million payment due on May 31, 2009 with all remaining principal, fees and interest amounts under our Revolving Facility to be due and payable on June 30, 2009. Net cash
generated from operating activities is a function of production volumes and commodity prices, both of which are inherently volatile and unpredictable, as well as operating efficiency and costs. Our
business, as with other extractive businesses, is a depleting one in which each gas equivalent unit produced must be replaced or our asset base and capacity to generate revenues in the future will
shrink. This was a factor in our 2008 results, which reflected a 24% lower proved reserve base at year-end. We were unable to replace the production we generated due to our reduced capital
spending program and higher drilling and operating costs. In addition to our existing rapid production decline curve, this will continue to be factor in 2009 as we operate under a severely limited
capital and operating budget. Less predictable than production declines from our proved reserves is the impact of constantly changing oil and natural gas prices on cash flows. We attempt to mitigate
the price risk with our hedging program. Reserves and production volumes are influenced, in part, by the amount of future capital expenditures. In turn, capital expenditures are influenced by many
factors including drilling results, oil and natural gas prices, industry conditions, prices, availability and cost of goods and services and the extent to which oil and natural gas properties are
acquired. In 2009, our capital expenditures will also be impacted by our liquidity issues and the related Deficiency under
our Revolving Facility, as well as the Amended Consent which imposes significant constraints on our capital expenditures.

Our
primary cash requirements are for exploration, development and acquisition of oil and natural gas properties, payment of preferred stock dividends, payment of derivative loss
settlements and the repayment of principal and interest on outstanding debt (including the Deficiency under our Revolving Facility). We have historically attempted to fund our exploration and
development activities primarily through internally generated cash flows and budget capital expenditures based largely on projected cash flows, however we do not anticipate that our cash flows will be
sufficient to fund our primary cash requirements. We routinely adjust capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, and cash flow. We
typically have funded acquisitions from borrowings under our credit facilities, cash flow from operations and sales of common stock and preferred stock, though we do not anticipate making any
acquisitions in the foreseeable future.

Significant
changes to working capital affects our liquidity in the short term. As of December 31, 2008, our outstanding debt was classified as current due to the amendment in the
maturity date to June 30, 2009 as provided by the Amended Consent which requires a $25 million payment due on May 31, 2009 with all remaining principal, fees and interest amounts
under our Revolving Facility to be due and payable on June 30, 2009 (see "Revolving Facility" below for additional discussion). Our derivative instrument asset is indicative of potential future
cash settlement inflows on our outstanding oil and natural gas derivative positions, which are scheduled to settle in future months. The fair market value represents the potential settlement for those
contracts if the market prices remain unchanged. Should commodity prices increase or decrease, the fair value of those outstanding contracts would change, as evidenced in 2008 as the position flipped
from a liability at year-end 2007 to an asset at year-end 2008. When our derivatives result in cash settlement outflows, we receive higher cash inflows on the sale of our
physical production at those higher market prices, thus providing us with funds to cover at least a portion of any derivative payments that may come due in the future. This was not true, however, for
the portion of our 2008 production that was overhedged. Approximately 115% of our natural gas production and approximately 190% of our anticipated crude oil production was hedged in 2008 as a result
of a decrease in expected production since the time we entered into our 2008 derivative positions.

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We
have historically used our credit facilities to supplement any deficiencies between operating cash flow and capital expenditures. Our outstanding debt balance at March 16, 2009
was $234.0 million.

During
2007, we realized increased cash flows as a result of our public and private stock offerings. We have also realized cash flows from the exercises of options and warrants to
acquire shares of our common stock, although we typically do not rely on proceeds from the exercise of warrants and stock
options to sustain our business, as the timing of their exercise is unpredictable. At December 31, 2008, 2007 and 2006, we had certain options outstanding and exercisable for shares of our
common stock.

We
realized approximately $19.2 million related to the sale of a pipeline and approximately 120 properties in Texas and Mississippi to various buyers during 2008, and we used the
proceeds to reduce outstanding debt and fund ongoing capital spending. In connection with our ongoing financial and strategic alternatives process, we are actively pursuing the possible sale of some
or all of our assets or other business combination involving the Company.

As
a result of the strategic alternatives process we began in late 2007, we reduced our planned capital spending for 2008 as compared to recent years. During the first quarter of 2008,
our Board of Directors approved a reduced capital budget. This program called for the drilling of 27 to 30 wells (10.4 to 10.7, net) during 2008, primarily in south Texas and, to a lesser extent, in
southeast New Mexico, complemented by selected expenditures for land and seismic. The recent worldwide financial and credit crisis has reduced the availability of liquidity and credit worldwide, and
the recent substantial declines in worldwide equity markets, including our stock prices, make it more difficult to effectively raise capital through equity issuances.

We
had cash and cash equivalents at December 31, 2008 of $8.5 million consisting primarily of short-term money market investments, as compared to
$7.2 million at December 31, 2007. Working capital was a deficit of $203.3 million as of December 31, 2008, as compared to a surplus of $2.3 million at
December 31, 2007. In 2008, we classified all of our outstanding debt as current due to the amendment in the maturity date to June 30, 2009 required by the Amended Consent.

For the Year Ended December 31,2008

2007

2006(in thousands)Net Cash Provided By Operating Activities

$
82,735

$
122,869

$
97,409Net Cash Used In Investing Activities


(52,157
)

(515,826
)

(140,412
)Net Cash Provided by (Used in) Financing Activities


(29,266
)

398,039


44,418


Net Cash Provided By Operating ActivitiesThe decrease in cash flows provided by operating activities for year ended December 31, 2008 as
compared to the same period in 2007 is primarily a result of cash settlement losses of approximately $18.1 million on our derivative contracts as compared to cash settlement gains of
$3.6 million in 2007. Another contributor to the decrease in cash flows in 2008 was a decrease in production revenue and an increase in cash costs such as severance taxes, oil and natural gas
operating expenses and G&A expenses, including strategic alternatives process costs and retention bonus payments. Changes in working capital increased total cash flows by $4.1 million in 2008
as compared to decreasing total cash flows by $2.0 million in 2007.

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

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Net
cash generated from operating activities is a function of production and commodity prices, which are inherently volatile and unpredictable, and costs of operating our business and
properties. In an effort to reduce the volatility realized on commodity prices, we enter into derivative instruments. Due to lower natural gas market pricing, we realized a benefit in cash settlement
gains of $4.5 million and $4.7 million on our natural gas derivatives during 2007 and 2006, respectively. Partially offsetting these cash inflows were cash settlement losses of
$0.9 million on our crude oil derivatives during 2007. Overall, oil and gas production revenue, including the effects of derivatives and hedging, for 2007 increased 24% over 2006.

Fluctuations
in commodity prices have been the primary reason for our short-term changes in cash flow from operating activities. 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. This was a factor in our 2008
results, which reflected a
24% lower proved reserve base at year-end. We were unable to replace the production we generated due to our reduced capital spending program and higher drilling and operating costs. This
will continue to be a factor in 2009 as we operate under a severely limited capital and operating budget.

Net Cash Used In Investing ActivitiesWe have historically reinvested a substantial portion of our cash flows in our drilling, acquisition, land
and
geophysical activities. Under our reduced 2008 program, we spent approximately $47.4 million on our drilling and operating program. We drilled 27 gross wells in 2008, of which 25 gross wells
were apparent successes. Leasehold, capitalized G&A and interest, and geological and geophysical activities accounted for expenditures of $12.7 million. There were also minimal capital
expenditures associated with computer hardware, office equipment and other miscellaneous capital charges. This limited program compares to the prior year in which our largest expenditure was the
acquisition that occurred in January 2007. During 2008, proceeds from the sale of certain non-core properties in Texas and Mississippi and a pipeline to various buyers totaled
approximately $19.2 million. In 2009, we do not anticipate that our cash flows will be sufficient to fund our primary cash requirements and reinvestment of cash flows in our drilling,
acquisition, land and geophysical activities will be severely limited.

Due
to the overhedged position in 2008, the cash settlements related to overhedged production are reflected in investing activities because they do not apply to operating revenue and are
similar in nature to an investment. Approximately 45% of our oil settlements and approximately 20% of our natural gas settlements are represented by the $10.6 million of speculative overhedged
derivative settlements in this section of the statement of cash flows. The remainder of cash settlements is located in net cash provided by operating activities. For further discussion of our
overhedged position, see "Approach to the Business" above. This was not a factor in 2007 or 2006.

We
used $515.8 million in investing activities during 2007. Acquisition costs of $375.2 million were related to the January 2007 Acquisition, which was the largest in our
history. Capital expenditures of $113.2 million were attributable to the drilling of 50 gross wells, 46 of which were apparently successful and 39 recompletions. Higher net capital costs per
well in 2007 as compared to prior years were due to higher average working interests and higher gross costs per well in Arkansas and Deep Frio project areas as compared to wells drilled in previous
years. General increases in costs of services as a result of a higher commodity price environment also contributed. Other spending included $20.5 million attributable to land holdings,
capitalized G&A and interest and $6.0 million for seismic data and other geological and geophysical expenditures. The remaining capital expenditures were associated with computer hardware and
office furniture and equipment. We also received $1.1 million during early 2007 from the sale of a portion of our interest in a Louisiana well.

During
the year ended December 31, 2006, we used $140.4 million in investing activities. Capital expenditures of $82.6 million were attributable to the drilling of
52 gross wells, 43 of which were apparently successful. Acquisition costs totaled $39.4 million, mainly related to the acquisition of

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additional
interests in the Chapman Ranch Field late in 2006 and final adjustments to the purchase price of the 2005 acquisition of Cinco Energy Corporation. Other spending included
$14.0 million attributable to land holdings, capitalized G&A and interest and $7.7 million for increased seismic data and other geological and geophysical expenditures. Drilling advances
to the operator of our Queen City properties decreased in 2006 by approximately $2.9 million. We also received $0.6 million during 2006 from the sale of our Buckeye properties. The
remaining capital expenditures were associated with computer hardware and office furniture and equipment.

Net Cash Provided By (Used in) Financing ActivitiesDuring the year ended December 31, 2008, we repaid $21.0 million under our Revolving
Facility using proceeds from our asset sales. We also paid quarterly dividends on our preferred stock in January, April, July and October 2008.

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

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

Revolving Facility

On January 30, 2007, we entered into the Revolving Facility with the Lenders, in favor of the Company and certain of its
wholly-owned subsidiaries in an amount equal to $750 million. The Revolving Facility has a letter of credit sub-limit of $20 million. The
Revolving Facility was scheduled to mature on January 31, 2011. At December 31, 2008, borrowings under the Revolving Facility bore interest at LIBOR plus an applicable margin ranging
from 1.25% to 2.50% or Prime plus a margin of up to 0.50%, with an unused commitment fee ranging from 0.50% to 0.25%, all of which depend on the utilization percentage of the conforming borrowing
base. At December 31, 2008, the interest rates applied to our outstanding Prime and LIBOR borrowings were 3.75% and 4.33%, respectively, and we had a rate of 0.25% applied to our unused
borrowing capacity.

As
of December 31, 2008, $239 million in total borrowings were outstanding under the Revolving Facility. The borrowing base was reduced from $320 million to
$300 million during the fourth quarter of 2007 and the conforming borrowing base was reduced from $300 million to $250 million. In early May 2008, our Revolving Facility's
borrowing base and conforming borrowing base were redetermined by our banks and set at $250 million and $225 million, respectively. These reductions were primarily the result of declines
in commodity prices, the sale of certain non-core assets during the first quarter of 2008 and the reduction of total proved reserves as reported in the year-end reserve reports
of our independent reserve engineers.

On
July 11, 2008, in connection with the proposed merger with Chaparral, we entered into a Consent. Agreement (the "Chaparral Consent"). Pursuant to the Chaparral Consent and
subject to the terms thereof, the Lenders deferred their right to conduct a borrowing base redetermination on or before June 30, 2008 and agreed to conduct the redetermination on
October 31, 2008. We paid the Lenders a fee of approximately $0.4 million in connection with the deferral of the redetermination. On November 5, 2008, the Lenders agreed to delay
the interim redetermination from October 31, 2008

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until
November 15, 2008. In consideration for this deferral, the Lenders placed a restriction upon the current borrowing base such that it was effectively lowered to $240 million until
the interim redetermination occurred. Pursuant to the terms of the Revolving Facility, upon the completion of the redetermination, our borrowing base would also be the conforming borrowing base. This
redetermination process was completed during January 2009 and the Lenders established a new borrowing base of $125 million under the Revolving Facility resulting in a borrowing base deficiency
of $114 million. Pursuant to the terms of the Revolving Facility, we elected to prepay the Deficiency in six equal monthly installments, with the first $19 million installment being due
on February 9, 2009. On February 9, 2009, we entered into the February Consent among us and the Lenders under the Revolving Facility deferring the payment date of the first
$19 million installment until March 10, 2009, and extending the due date for each subsequent installment by one month with the last of the six $19 million installment payments to
be due on August 10, 2009. In connection with the February Consent, we agreed to prepay $5.0 million of our outstanding advances under the Revolving Facility, in two equal installments.
The first $2.5 million prepayment was paid on February 9, 2009 and the second $2.5 million prepayment was paid on February 23, 2009 with each of the prepayments to be
applied on a pro rata basis to reduce the remaining six $19 million deficiency payments. On March 10, 2009, we entered into the March Consent with the Lenders under the Revolving
Facility, which provided, among other things, for the extension of the due date for the first installment to repay the Deficiency from March 10, 2009 to March 17, 2009. Notwithstanding
such extension, we agreed with the Lenders that each of the other five equal installment payments required to eliminate the Deficiency would be due and payable as provided for in the February Consent.

On
March 16, 2009, we entered into the Amended Consent which provides, among other things, (1) that we will make a $25 million payment on May 31, 2009 with
all remaining principal, fees and interest amounts under our Revolving Facility to be due and payable on June 30, 2009, (2) that it will be an event of default (i) if we fail to
have executed and delivered on or before May 15, 2009 at least one of the following (a) a commitment letter from a lender or group of lenders reasonably satisfactory to our Lenders
providing for the provision by such lender or group of lenders of a credit facility in an amount sufficient to repay all of our obligations under the Revolving Facility on or before June 30,
2009, (b) a merger agreement or similar agreement involving us as part of a transaction that results in the repayment of our obligations under the Revolving Facility on or before
June 30, 2009, and (c) a purchase and sale agreement with a buyer or group of buyers reasonably acceptable to our Lenders providing for a sale transaction by us that results in the
repayment of all of our obligations under the Revolving Facility on or before June 30, 2009, or (ii) if we are in default under or our hedging arrangements have been terminated or cease
to be effective without the prior written consent of our Lenders, (3) that our advances under the Revolving Facility will bear interest at a rate equal to the greater of (a) the
reference rate publicly announced by Union Bank of California, N.A. for such day, (b) the Federal Funds Rate in effect on such day plus 0.50% and (c) a rate determined by the
Administrative Agent to be the Daily One-Month LIBOR (as defined in the Revolving Facility), in each case plus 2.5% or, during the continuation of an event of default, plus 4.5% (resulting
in an effective interest rate of approximately 5.75% as of March 16, 2009), (4) for limitations on the making of capital expenditures and certain investments, and (5) for the
elimination of the current ratio, leverage ratio and interest coverage ratio covenant requirements. To comply with the terms of the Amended Consent, we anticipate that we will need to (i) sell
select individual assets prior to May 31, 2009 to enable us to make the $25 million payment which is due on May 31, 2009, and/or (ii) negotiate a commitment letter with a
new lender or group of lenders prior to May 15, 2009 in an amount sufficient to repay all of our obligations under the Revolving Facility on or before June 30, 2009, and/or
(iii) have negotiated the sale, merger or other business combination involving us which results in the repayment of all of our obligations under the Revolving Facility prior to May 15,
2009 and to have closed such transaction on or before June 30, 2009. The Amended Consent limits the making of capital expenditures and we anticipate a severe curtailment of our drilling plans
and other capital expenditures in 2009.

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If
we breach any of the provisions of the Amended Consent or the Revolving Facility, our Lenders will be entitled to declare an event of default, at which point the entire unpaid
principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, would become immediately due and payable. In any event, the entire unpaid
principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, will be payable on June 30, 2009 unless earlier paid or a further
extension with respect to payment is negotiated with our Lenders. Our Lenders may take action to enforce their rights with respect to the outstanding obligations under the Revolving Facility. Because
substantially all of our assets are pledged as collateral under the Revolving Facility, if our Lenders declare an event of default, they would be entitled to foreclose on and take possession of our
assets. In such an event, we may be forced to liquidate or to otherwise seek protection under Chapter 11 of the U.S. Bankruptcy Code. These matters, as well as the other risk factors related to
our liquidity and financial position raise substantial doubt as to our ability to continue as a going concern. With respect to our compliance with the Amended Consent, there can be no assurance that
we will be able to further negotiate the terms of the Amended
Consent or negotiate a further restructuring of the related indebtedness or that we will be able to make any required payments when they become due. Moreover, there can be no assurance that we will be
successful in our efforts to comply with the terms of the Amended Consent, including our ongoing efforts to evaluate and assess our various financial and strategic alternatives (which may include the
sale of some or all of our assets, a merger or other business combination involving the Company, or the restructuring or recapitalization of the Company). If such efforts are not successful, we may be
required to seek protection under Chapter 11 of the U.S. Bankruptcy Code. SeeITEM 1A. "RISK FACTORSOur January 2009 borrowing base
redetermination resulted in a $114 million borrowing base deficiency under our Revolving Facility and we may not be able to satisfy the terms and conditions of our Amended Consent relating
thereto or to otherwise repay our borrowing base deficiency or satisfy our other liabilities."

Our
obligations under the Revolving Facility are secured by substantially all of our assets. The Revolving 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 Revolving Facility restricts common stock
dividends and certain distributions of cash or properties and certain liens but no longer contains any financial covenants.

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

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Shelf Registration Statement & Offerings

In the third quarter of 2007, the SEC declared effective our registration statement filed with the SEC that registered securities of up
to $500 million of any combination of debt securities, preferred stock, common stock, warrants for debt securities or equity securities of the Company and guarantees of debt securities by our
subsidiaries. Net proceeds, terms and pricing of the offering of securities issued under the shelf registration statement will be determined at the time of the offerings. The shelf registration
statement does not provide assurance that we will or could sell any such securities. Our ability to utilize our shelf registration statement for the purpose of issuing, from time to time, any
combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities will depend upon, among other things, market conditions and the existence of
investors who wish to purchase our securities at prices acceptable to us. However, because the aggregate market value of our outstanding common stock is less than $75 million, the type and
amount of any securities offering under the registration statement may be limited.

Convertible Preferred Stock

As noted above, we completed the public offering of 2,875,000 shares of our Convertible Preferred Stock in January 2007. We used the
$138.4 million in net proceeds from this offering, along with the proceeds from the concurrent common stock offering of $138.1 million and borrowings under our Revolving Facility, to
finance the January 2007 Acquisition and to refinance our prior credit facility.

Dividends.The Convertible Preferred Stock accumulates dividends at a rate of $2.875 for each share of Convertible Preferred Stock per
year.
Dividends are cumulative from the date of first issuance and, to the extent payment of dividends is not prohibited by our debt agreements, assets are legally available to pay dividends and our Board
of Directors or an authorized committee of our Board declares a dividend payable, we will pay dividends in cash, every quarter. The first payment was made on April 15, 2007 and we continued to
make quarterly dividends payments through October 15, 2008. The Board did not declare a dividend in the fourth quarter of 2008 due to our current lack of liquidity. Cumulative dividends in
arrears at December 31, 2008 amounted to $1.7 million.

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

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

Ranking.Our Convertible Preferred Stock ranks:



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

Optional redemption.If fewer than 15% of the shares of Convertible Preferred Stock issued in the January 2007 offering (including any
additional
shares issued pursuant to the underwriters' over-allotment option) are outstanding, we may, at any time on or after January 20, 2010, at our option, redeem for cash all such
Convertible Preferred Stock at a redemption price equal to the liquidation preference of $50.00 plus any accrued and unpaid dividends, if any, on a share of Convertible Preferred Stock to, but
excluding, the redemption date, for each share of Convertible Preferred Stock.

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

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

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

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

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



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

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

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



Off Balance Sheet Arrangements

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

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Contractual Cash Obligations

The following table summarizes our contractual cash obligations as of December 31, 2008 by payment due date:

Total

Less than
1 Year

1-3
Years

4-5
Years

After 5
Years(in thousands)Debt(1)

$
239,000

$
239,000

$


$


$
FIN 48 expected liabilities(2)


102





102





Delivery commitment(3)


2,005





2,005





Operating leases


5,426


1,188


3,555


683


Total contractual cash obligations(4)(5)(6)

$
246,533

$
240,188

$
5,662

$
683

$



---

FAIR VALUE MEASUREMENTS

Effective January 1, 2008, we partially adopted SFAS No. 157,Fair Value
Measurements,which provides a common definition of fair value, establishes a framework for measuring
fair value and expands disclosures about fair value measurements, but does not require any new fair value measurements. The partial adoption of SFAS No. 157 had no impact on our consolidated
financial statements, but it did result in additional required disclosures as set forth in Note 10 to our consolidated financial statements. In February 2008, the FASB issued
FSP 157-2,Effective Date of FASB Statement No. 157, which delays the effective date of SFAS No. 157 for all
non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the consolidated financial statements on a recurring basis
(at least annually). Accordingly, we have not yet applied the provisions of SFAS No. 157 to our AROs.

SFAS
No. 157 defines fair value as the price that would be received to sell an asset or transfer a liability in an orderly transaction between market participants at the
measurement date. Currently the only fair value measurements we utilize are related to our AROs and derivative instruments. While our

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derivative
instruments are executed in liquid markets where price transparency exists, we are not involved in the monthly calculation of fair value. We utilize valuations provided by our
counterparties, which include inputs such as commodity exchange prices, over-the-counter quotes, volatility, historical correlations of pricing data and LIBOR and other liquid
money market instrument rates. Our counterparties utilize internally developed basis curves that incorporate observable and unobservable market data. Although we believe these valuations are the best
estimates of the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ from these estimates, and the differences could be material.

SFAS
No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value based on observable and unobservable data and
categorizes the inputs into three levels, with the highest priority given to Level 1 and the lowest priority given to Level 3. The three levels of the fair value hierarchy defined by
SFAS No. 157 are as follows:



Determining
the appropriate classification of our fair value measurements within the fair value hierarchy requires management's judgment regarding the degree to which market data is observable or
corroborated by observable market data. Currently we have categorized derivative instruments' fair value measurements as Level 3 and expect to categorize our AROs' fair value measurements as
Level 3 upon full adoption of SFAS No. 157. As interpretations of SFAS No. 157 evolve, our classification of certain instruments within the hierarchy may be revised. See "Critical
Accounting Policies and EstimatesDerivative and Hedging Activities" above, "Risk Management ActivitiesDerivatives and Hedging" below and Note 9 to our consolidated
financial statements for additional discussion of our derivative instruments.

In
conjunction with the adoption of SFAS No. 157, we also adopted SFAS No. 159,The Fair Value Option for Financial Assets and Financial
LiabilitiesIncluding an Amendment of FASB Statement No. 115,effective January 1, 2008. SFAS No. 159 allows a company the option to value its
financial assets and liabilities, on an instrument by instrument basis, at fair value, and include the change in fair value of such assets and liabilities in its results of operations. We did not
elect to apply the provisions of SFAS No. 159 to any of our financial assets or liabilities. Accordingly, there was no impact to our consolidated financial statements resulting from the
adoption of SFAS No. 159.

RISK MANAGEMENT ACTIVITIESDERIVATIVES AND HEDGING

Due to the volatility of oil and natural gas prices, from time to time, we may enter into price-risk management
transactions (e.g., swaps, collars and floors) related to our expected oil and natural gas production to seek to achieve a more predictable cash flow, as well as to reduce exposure to commodity
price fluctuations. While the use of these arrangements may limit our ability to benefit from increases in the price of oil and natural gas, it is also intended to reduce our potential exposure to
adverse price movements. Our arrangements, to the extent we enter into any, are intended to apply to only a portion of our expected production, and thereby provide only partial price protection
against declines in oil and natural gas prices. None of these instruments were, at the time of their execution, intended to be used for trading or speculative purposes, but a portion of these
instruments was subsequently deemed as such because of the decrease in our 2008 production. The use of derivative

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instruments
involves some credit risk, but generally we place our derivative transactions with major financial institutions that we believe are financially stable; however, in light of the recent
global
financial crisis, there can be no assurance of the foregoing. In the event any such counterparty fails to perform, our financial results could be adversely affected and we could incur losses and its
liquidity could be negatively impacted. On a quarterly basis, our management sets all of our price-risk management policies, including volumes, types of instruments and counterparties.
These policies are implemented by management through the execution of trades by the Chief Financial Officer after consultation and concurrence by the President and Chairman of the Board. Our Board of
Directors monitors the Company's price-risk management policies and trades on a monthly basis.

All
of these price-risk management transactions are considered derivative instruments and accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities(as
amended). These derivative instruments are intended to hedge our price risk and may be
considered hedges for economic purposes. There are two types of accounting treatments for derivatives, (i) mark-to-market accounting and (ii) cash flow hedge
accounting. For a discussion of these accounting treatments, see Note 9 to our consolidated financial statements. We currently apply mark-to-market accounting treatment
to all of our derivative contracts. All derivatives are recorded on the balance sheet at fair value and the changes in fair value are presented in total revenue on the statement of operations. The
following table provides additional information regarding our various derivative transactions that were recorded at fair value on the balance sheet as of December 31, 2008.

(in thousands)Fair value of contracts outstanding at December 31, 2007

$
(12,329
)Contracts realized or otherwise settled during the period


(28,712
)Fair value at December 31, 2008 of new contracts when entered into during 2008:Asset


Liability


Changes in fair values attributable to changes in valuation techniques and assumptions


Other changes in fair values


56,448Fair values of contracts outstanding at December 31, 2008

$
15,407


The
following table details the fair value of our commodity-based derivative contracts by year of maturity and valuation methodology as of December 31, 2008.

Fair Value of Contracts at December 31, 2008Source 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(in thousands)Prices actively quoted:

$


$


$


$


$
Prices provided by other external sources:Asset


15,407











15,407Liability














Prices based on models and other valuation methods:














Total

$
15,407

$


$


$


$
15,407


TAX MATTERS

At December 31, 2008, we had cumulative NOL carryforwards for federal and state income tax purposes of approximately
$124.9 million and $21.4 million, respectively, without consideration of valuation allowances. The federal and state NOL carryforwards will expire in varying amounts between

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2009
and 2028. In addition to the deferred tax assets associated with NOLs, we have additional net deferred tax assets of approximately $65.0 million related to both federal and state tax
positions. In recording deferred income tax assets, we consider whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization
of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. We consider the scheduled
reversal of deferred income tax liabilities and projected future taxable income for this determination. We believe that after considering all the available objective evidence, both positive and
negative, historical and prospective, with greater weight given to the historical evidence, and in light of the current market situation and the uncertainty surrounding our Revolving Facility and
related Amended Consent, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and therefore have established a full valuation allowance to
reduce our net deferred tax asset to zero at December 31, 2008. We will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in
future reporting periods. If we achieve profitable operations in the future, we may reverse a portion of the valuation allowance in an amount at least sufficient to eliminate any tax provision in that
period. The valuation allowance has no impact on our NOL position for tax purposes, and if we generate taxable income in future periods, we will be able to use our NOLs to offset taxes due at that
time.

Our
ability to utilize federal and state NOL carryforwards in cases where the NOL was acquired in a reorganization may be subject to limitations under Section 382 of the Internal
Revenue Code of 1986, as amended ("Section 382") if we undergo a majority ownership change as defined by Section 382.

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

At
December 31, 2008, under Section 382 rules, approximately $80.5 million of our total federal NOL carryforward of $124.9 million was subject to a potential
annual limitation of $12 million. Of that $80.5 million, $22 million was subject to further annual limitations. The $22 million amount represents the following two separate
limitations which occurred prior to 2008: (1) $17.4 million acquired in a December 2003 merger, which is subject to an annual limitation of approximately $1 million per year

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and
(2) $5.4 million acquired in a November 2005 acquisition, which is subject to an annual limitation of approximately $2 million per year.

FASB
Interpretation No. 48 ("FIN 48"),Accounting for Uncertainty in Income Taxes, provides guidance on recognition and
measurement of uncertainties in income taxes. FIN 48 requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would
more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial
statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. See Notes 2 and 17 to our
consolidated financial statements. Upon adoption of FIN 48 on January 1, 2007, we recognized a liability of approximately $0.5 million, which was a reduction in the
January 1, 2007 retained earnings balance. During second quarter 2008, we recorded an income tax benefit of approximately $0.4 million as a result of the conclusion of a state audit
where no prior benefit was taken for an uncertain tax position, which is now effectively settled without adjustment by the state tax authorities.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

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

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

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In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activitiesan
amendment of FASB Statement No. 133("SFAS No. 161"). SFAS No. 161 requires entities to provide enhanced disclosures about (a) how and why an entity
uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and (c) how derivative
instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. SFAS No. 161 is effective for annual periods beginning on or after
November 15, 2008. Early application of SFAS No. 161 is encouraged, as are comparative disclosures for earlier periods at initial adoption. We will adopt SFAS No. 161 on
January 1, 2009 and do not expect adoption of this statement to impact our consolidated financial statements, but we do expect it to impact disclosures made in our future quarterly and annual
filings.

In
December 2008, the SEC issued the final rule,"Modernization of Oil and Gas Reporting," which adopts revisions to the SEC's oil and
natural gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. Early adoption of the new
rules is prohibited. The new rules are intended to provide investors with a more meaningful and comprehensive understanding of oil and natural gas reserves to help investors evaluate their investments
in oil and natural gas companies. The new rules are also designed to modernize the oil and natural gas disclosure requirements to align them with current practices and changes in technology. The new
rules include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves and permitting
disclosure of probable and possible reserves. We are currently evaluating the potential impact of these rules. The SEC is discussing the rules with the FASB staff to align FASB accounting standards
with the new SEC rules. These discussions may delay the required compliance date. Absent
any change in the effective date, we will begin complying with the disclosure requirements in our annual report on Form 10-K for the year ended December 31, 2009.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk from changes in interest rates and commodity prices. We use a Revolving Facility, which has a floating
interest rate. We are not subject to fair value risk resulting from changes in our floating interest rates. The use of floating rate debt instruments provides a benefit due to downward interest rate
movements but does not limit us to exposure from future increases in interest rates. Based on the year-end December 31, 2008 outstanding borrowings and interest rates of 3.75% and
4.33% applied to various borrowings, a 10% change in these interest rates would result in an increase or decrease in interest expense of approximately $1.0 million on an annual basis.

The
debt and equity markets have recently exhibited adverse conditions. The unprecedented volatility and upheaval in the capital markets may increase costs associated with issuing debt
instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets. We believe the recent events in the global markets had significant impact on
our recent borrowing base redetermination that resulted in a $114 million borrowing base deficiency. The continued credit crisis and related turmoil in the global financial system and economic
recession in the U.S. create financial challenges if conditions do not improve and will affect our ability to access credit markets. We will continue to monitor our liquidity and the capital markets
as we continue to assess our financial and strategic alternatives.

As
of December 31, 2008, our outstanding debt was classified as current due to the amendment in the maturity date to June 30, 2009 as provided by the Amended Consent which
requires a $25 million payment due on May 31, 2009 with all remaining principal, fees and interest amounts under our Revolving Facility to be due and payable on June 30, 2009.

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In
the normal course of business, we enter into derivative transactions, including commodity price collars, swaps and floors, to mitigate our exposure to commodity price movements. They
are not intended for trading or speculative purposes. While the use of these arrangements may limit the benefit
to us of increases in the price of oil and natural gas, it also limits the downside risk of adverse price movements. During early 2007, we put in place several natural gas and crude oil derivatives to
hedge our expected 2008 and 2009 production to achieve a more predictable cash flow. As a result of changes to our forecasted 2008 production and the impact of certain asset divestitures, both of
which reduced production as compared to that expected at the time we entered into the derivative contracts, we had approximately 115% and 190% of our 2008 natural gas and crude oil production,
respectively, covered by derivative contracts. This overhedged position exposed us to greater risk of commodity price increases because we did not have the physical production cash inflows to offset
the losses incurred on the portion of the contracts that were overhedged. Please refer to Note 9 to our consolidated financial statements for a discussion of these contracts. The following is a
list of contracts outstanding at December 31, 2008:

Transaction Date

Transaction
Type

Beginning

Ending

Price
Per Unit

Volumes
Per Day

Fair Value
Outstanding as of
December 31, 2008(in thousands)Natural Gas(1):04/07

Collar


01/01/09


12/31/09

$7.75-$10.00

10,000 MMBtu


6,68810/07

Collar


01/01/09


12/31/09

$7.75-$10.08

10,000 MMBtu


6,702Crude Oil(2):10/07

Collar


01/01/09


12/31/09

$70.00-$93.55

300 Bbl


2,017$
15,407


---

At
December 31, 2008, the fair value of the outstanding contracts was a net asset of approximately $15.4 million. SeeITEM 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 hedge to increase or decrease by
approximately $1.5 million.

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

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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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 ("CEO") and Chief Financial Officer ("CFO"), as appropriate to allow timely decisions regarding required disclosure.

In
accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management,
including our CEO and 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.

(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 Rule 13a-15(f) of the Exchange Act. Internal control over financial reporting is a
process designed by, or under the supervision of, the Company's
principal executive and principal financial officers, or persons performing similar functions and influenced by the Company's Board of Directors, management and other personnel, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United
States of America ("GAAP"). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate or insufficient because of changes 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, 2008. The Company's management conducted its assessment in
accordance with theInternal ControlIntegrated Frameworkissued by the Committee of Sponsoring Organizations of the

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Treadway
Commission ("COSO"). Management has concluded that the internal control over financial reporting was effective as of December 31, 2008.

BDO
Seidman, LLP, the independent registered public accounting firm who also audited the Company's consolidated financial statements, has issued its own attestation report on the
effectiveness of internal controls over our financial reporting as of December 31, 2008, which is filed herewith.

(c) Changes in Internal Control Over Financial Reporting.There have not been any changes in the Company's internal control over
financial reporting
during the fiscal quarter ended December 31, 2008 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

(d) Report of Independent Registered Public Accounting Firm

Board
of Directors and Stockholders
Edge Petroleum Corporation
Houston, Texas

We
have audited Edge Petroleum Corporation's internal control over financial reporting as of December 31, 2008, based on criteria established inInternal
ControlIntegrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Company's management is
responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying
"Item 9A, Management's Report on Internal Control Over Financial Reporting". Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our
audit.

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

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

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

In
our opinion, Edge Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO
criteria.

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We
also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Edge Petroleum Corporation as
of December 31, 2008 and 2007 and the related consolidated statements of operations, comprehensive income (loss), stockholders' equity, and cash flows for each of the three years in the period
ended December 31, 2008, and our report dated March 16, 2009 included an explanatory paragraph that expressed substantial doubt about the Company's ability to continue as a going
concern.

/S/
BDO SEIDMAN, LLP
BDO Seidman, LLP
Houston, Texas
March 16, 2009

ITEM 9B.    OTHER INFORMATION

None.

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PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information regarding directors and executive officers required underITEM 10will
be contained within the definitive Proxy Statement for the Company's 2009 Annual Meeting of Shareholders (the "Proxy Statement") under the headings "Election of Directors," "Meetings and Committees of
the Board" and "Compliance with Section 16(a) of the Exchange Act" and is incorporated herein by reference. The Proxy Statement will be filed pursuant to Regulation 14A with the
Securities and Exchange Commission not later than 120 days after December 31, 2008, or the Company will file an amendment to this Form 10-K within the same time period
that includes the required information. Pursuant to Item 401(b) of Regulation S-K certain of the information required by this item with respect to our executive officers is
set forth in Part I of this report.

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

ITEM 11.    EXECUTIVE COMPENSATION

The information required byITEM 11will be contained in the Proxy Statement under the
headings "Executive Compensation," "Compensation Committee Interlocks and Insider Participation," "Compensation Committee Report" and "2008 Director Compensation" and is incorporated herein by
reference.

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

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

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

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

ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES

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

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PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

2.1



Amended and Restated Combination Agreement by and among (i) Edge Group II Limited Partnership, (ii) Gulfedge Limited Partnership, (iii) Edge Group Partnership, (iv) Edge Petroleum Corporation,
(v) Edge Mergeco, Inc. and (vi) the Company, dated as of January 13, 1997 (Incorporated by reference from Appendix A to the Joint Proxy Statement/Prospectus contained in the Company's Registration Statement on Form S-4/A
filed on January 15, 1997 (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.


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2.7



Agreement and Plan of Merger, dated July 14, 2008, among Chaparral Energy, Inc., Chaparral Exploration, L.L.C. and Edge Petroleum Corporation (Incorporated by reference from exhibit 2.1 to the
Company's Current Report on Form 8-K filed July 15, 2008). Pursuant to Item 601(b)(2) of Regulation S-K, the Company had omitted the disclosure schedules to the Merger Agreement from this Exhibit 2.1. 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 (File No. 000-22149)).3.5



First Amendment to Bylaws of the Company on September 28, 1999 (Incorporated by reference from exhibit 3.2 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30,
 1999 (File No. 000-22149)).3.6



Second Amendment to Bylaws of the Company on May 7, 2003 (Incorporated by reference from exhibit 3.4 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended March 31,
2003).3.7



Certificate of Designations establishing the 5.75% Series A cumulative convertible perpetual preferred stock, dated January 25, 2007 (Incorporated by reference to exhibit 3.1 to the Company's Current
Report on Form 8-K filed January 30, 2007).3.8



Third Amendment to Bylaws of Edge Petroleum Corporation on October 21, 2008 (Incorporated by reference to exhibit 3.4 to the Company's Current Report on Form 8-K filed October 23,
2008).4.1



Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference from exhibit 10.1(a) to Miller's Annual Report on Form 10-K for the year ended December 31, 1997
(File No. 000-23431)).4.2



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's Registration Statement on Form S-8 filed on
April 11, 2001 (Registration No. 333-58678)).4.3



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's Registration Statement on Form S-8 filed on
April 11, 2001 (Registration No. 333-58678)).4.4



Form of Miller Stock Option Agreement (Incorporated by reference from exhibit 10.1(b) to Miller's Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 000-23431)).


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4.5



Fourth Amended and Restated Credit Agreement dated January 31, 2007 by and among Edge Petroleum Corporation, as borrower, and Union Bank of California, N.A., as Administrative Agent and Issuing Lender, and the
other lenders party thereto (Incorporated by reference from exhibit 4.1 to the Company's Current Report on Form 8-K filed on February 5, 2007).4.6



Amendments No. 1, 2 and 3 to the Fourth Amended and Restated Credit Agreement dated as of July 11, 2007, December 10, 2007 and May 8, 2008, respectively, by and among Edge Petroleum Corporation, as
borrower, and Union Bank of California, N.A., as Administrative Agent and Issuing Lender, and the other lenders party thereto (Incorporated by reference from exhibit 4.9 to the Company's Quarterly Report on Form 10-Q for the quarterly
period ending March 31, 2008 filed on May 12, 2008).4.7



Consent, executed July 11, 2008, among Edge Petroleum Corporation, the Lenders party thereto and Union Bank of California, N.A., as administrative agent for such Lenders (Incorporated by reference from
exhibit 4.1 to the Company's Current Report on Form 8-K filed July 15, 2008).4.8



Letter Agreement dated November 5, 2008 by and among Edge Petroleum Corporation, Union Bank of California, N.A., as Administrative Agent and Issuing Lender, and the other lenders party thereto (Incorporated
by reference from exhibit 4.11 to the Company's Quarterly Report on Form 10-Q for the quarterly period ending September 30, 2008 filed November 10, 2008).4.9



Consent and Agreement, executed February 9, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders. (Incorporated by
reference from exhibit 4.1 to the Company's Current Report on Form 8-K filed February 9, 2009).4.10



Consent and Agreement, executed March 10, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders. (Incorporated by reference
from exhibit 4.1 to the Company's Current Report on Form 8-K filed March 10, 2009).4.11



Consent and Agreement No. 4 executed March 16, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders.
(Incorporated by reference from exhibit 4.1 to the Company's Current Report on Form 8-K filed March 16, 2009).10.1



Form of Indemnification Agreement between the Company and each of its directors (Incorporated by reference from exhibit 10.7 to the Company's Registration Statement on Form S-4 (Registration
No. 333-17269)).10.2



Stock Option Plan of Edge Petroleum Corporation, a Texas corporation (Incorporated by reference from exhibit 10.13 to the Company's Registration Statement on Form S-4 (Registration No. 333-17269)).10.3



Employment Agreement dated as of November 16, 1998, by and between the Company and John W. Elias (Incorporated by reference from exhibit 10.12 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1998 (File No. 000-22149)).10.4



Amended and Restated Incentive Plan of Edge Petroleum Corporation as Amended and Restated Effective as of August 1, 2006 (Incorporated by reference from exhibit 10.4 to the Company's Quarterly Report on
Form 10-Q for the quarterly period ending June 30, 2006).


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10.5



Edge Petroleum Corporation Incentive Plan "Standard Non-Qualified Stock Option Agreement" by and between Edge Petroleum Corporation and the Officers named therein (Incorporated by reference from exhibit 10.2 to the
Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999 (File No. 000-22149)).10.6



Edge Petroleum Corporation Incentive Plan "Director Non-Qualified Stock Option Agreement" by and between Edge Petroleum Corporation and the Directors named therein (Incorporated by reference from exhibit 10.3 to
the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999 (File No. 000-22149)).10.7



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).10.8



Form of Employee Restricted Stock Award Agreement under the Incentive Plan of Edge Petroleum Corporation (Incorporated by reference from exhibit 10.15 to the Company's Quarterly Report on Form 10-Q/A for the
quarterly period ended March 31, 1999 (File No. 000-22149)).10.9



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)).10.10



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)).*10.11



Summary of Compensation of Non-Employee Directors.*10.12



Salaries and Certain Other Compensation of Executive Officers.10.13



Description of Annual Cash Bonus Program for Executive Officers (Incorporated by reference from exhibit 10.2 to the Company's Current Report on Form 8-K filed March 12, 2007).10.14



New Base Salaries and Long-Term Incentive Awards for Certain Executive Officers (Incorporated by reference from exhibit 10.1 to the Company's Current Report on Form 8-K filed August 29,
2006).10.15



Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated November 16, 2006 (Incorporated by reference to exhibit 10.1 to the
Company's Current Report on Form 8-K filed January 16, 2007).10.16



Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated November 16, 2006 (Incorporated by reference to exhibit 10.2 to the
Company's Current Report on Form 8-K filed January 16, 2007).10.17



First Amendment of Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated December 16, 2006 (Incorporated by reference to
exhibit 10.3 to the Company's Current Report on Form 8-K filed January 16, 2007).


92

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Table of Contents

10.18



Second Amendment of Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated January 15, 2007 (Incorporated by reference to
exhibit 10.1 to the Company's Current Report on Form 8-K filed January 19, 2007).10.19



First Amendment of Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated January 15, 2007 (Incorporated by reference to
exhibit 10.2 to the Company's Current Report on Form 8-K filed January 19, 2007).10.20



Third Amendment of Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated January 31, 2007 (Incorporated by reference to
exhibit 10.6 to the Company's Current Report on Form 8-K filed February 5, 2007).10.21



New Base Salaries of Executive Officers (Incorporated by reference from Exhibit 10.1 to the Company's Current Report on Form 8-K filed March 12, 2007).10.22



Form of Amended and Restated Severance Agreement dated April 3, 2008, between the Company and Executive Officers of the Company Named Therein (Incorporated by reference from exhibit 10.1 to the Company's
Current Report on Form 8-K filed April 4, 2008).10.23



Amended and Restated Severance Agreement dated April 3, 2008, between the Company and John W. Elias (Incorporated by reference from exhibit 10.2 to the Company's Current Report on Form 8-K filed
April 4, 2008).10.24



Amended and Restated Employment Agreement dated April 3, 2008, between the Company and John W. Elias (Incorporated by reference from exhibit 10.3 to the Company's Current Report on Form 8-K filed
April 4, 2008).10.25



First Amendment to Amended and Restated Severance Agreement, dated July 14, 2008, between the Company and John W. Elias (Incorporated by reference from exhibit 10.1 to the Company's Current Report on
Form 8-K filed July 15, 2008).10.26



First Amendment to Second Amended and Restated Severance Agreement, dated July 14, 2008, between the Company and Executive Officers of the Company Named Therein (Incorporated by reference from exhibit 10.2
to the Company's Current Report on Form 8-K filed July 15, 2008).10.27



Merger Termination Agreement, dated December 16, 2008, among Chaparral Energy, Inc., Chaparral Exploration, L.L.C. and Edge Petroleum Corporation (Incorporated by reference to exhibit 10.1 to the
Company's Current Report on Form 8-K filed December 17, 2008).10.28



Termination and Settlement Agreement, dated December 16, 2008, among Magnetar Financial LLC, Investment Partners II (B), LLC, QRA SR, LLC, Triangle Peak Partners Private Equity, LP, Post Oak
Energy Capital, LP, Chaparral Energy, Inc., Chaparral Exploration, L.L.C. and Edge Petroleum Corporation (Incorporated by reference to exhibit 10.2 to the Company's Current Report on Form 8-K filed December 17,
2008).*12.1



Statement of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.*21.1



Subsidiaries of the Company.*23.1



Consent of BDO Seidman, LLP.*23.2



Consent of Ryder Scott Company.


93

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Table of Contents

*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 Gary L. Pittman, 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 Section 906 of the Sarbanes-Oxley Act of 2002.*32.2



Certification by Gary L. Pittman, Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*99.1



Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 2008.*99.2



Summary of Reserve Report of W. D. Von Gonten & Co. Petroleum Engineers as of December 31, 2008.


---

94

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Table of Contents

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 CorporationBy

/s/ JOHN W. ELIAS John W. Elias Chief Executive Officer and Chairman
of the BoardDate: March 16, 2009


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 John W. Elias Chief Executive Officer and Chairman of the Board
(Principal Executive Officer)

Date: March 16, 2009By

/s/ GARY L. PITTMAN Gary L. Pittman Executive Vice President and Chief Financial Officer
(Principal Financial Officer)

Date: March 16, 2009By

/s/ KIRSTEN A. HINK Kirsten A. Hink Vice President and Controller
(Principal Accounting Officer)

Date: March 16, 2009By

/s/ THURMON M. ANDRESS Thurmon Andress Director

Date: March 16, 2009By

/s/ VINCENT S. ANDREWS Vincent Andrews Director

Date: March 16, 2009By

/s/ JONATHAN CLARKSON Jonathan Clarkson Director

Date: March 16, 2009


95

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Table of Contents

By

/s/ MICHAEL A. CREEL Michael A. Creel Director

Date: March 16, 2009By

/s/ JOHN SFONDRINI John Sfondrini Director

Date: March 16, 2009By

/s/ ROBERT W. SHOWER Robert W. Shower Director

Date: March 16, 2009By

/s/ DAVID F. WORK David F. Work Director

Date: March 16, 2009


96

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Table of Contents

EDGE PETROLEUM CORPORATION        Index to Consolidated Financial Statements and Supplementary Information



CONSOLIDATED FINANCIAL STATEMENTSAudited Financial Statements:Report of Independent Registered Public Accounting Firm


F-2Consolidated Balance Sheets as of December 31, 2008 and 2007


F-3Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007
and 2006


F-4Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2008,
2007 and 2006


F-5Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and
2006


F-6Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2008,
2007 and 2006


F-7Notes to Consolidated Financial Statements


F-8Unaudited Information:Supplementary Information to Consolidated Financial Statements


F-50


CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

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

F-1

---





Table of Contents



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 (the "Company") as of December 31, 2008 and 2007 and the related consolidated statements
of operations, comprehensive income (loss), stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2008. 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, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting
principles generally accepted in the United States of America.

As
discussed in Note 2 to the consolidated financial statements, effective January 1, 2007, the Company adopted the provisions of Financial Accounting Standards Board
Interpretation No. 48, "Accounting for Uncertainty in Income Taxes."

The
accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial
statements, at December 31, 2008, as a result of a deficiency in its revolving credit agreement subsequent to year end, the Company is in a negative working capital position with significant
payments due June 30, 2009 under the revolving credit agreement. This condition gives rise to substantial doubt about the Company's ability to continue as a going concern. Management's plans in
regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We
also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) Edge Petroleum Corporation's internal control over financial
reporting as of December 31, 2008, based on criteria established inInternal ControlIntegrated Frameworkissued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 16, 2009 expressed an unqualified opinion thereon.

|                                                                    |  | 
|------------------------------------------------------------------- |  | 
|/s/ BDO SEIDMAN, LLP BDO Seidman, LLP
Houston, Texas
March 16, 2009 |  | 

F-2

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Table of Contents



EDGE PETROLEUM CORPORATION        CONSOLIDATED BALANCE SHEETS

December 31,2008

2007(in thousands, except share data)ASSETSCURRENT ASSETS:Cash and cash equivalents

$
8,475

$
7,163Accounts receivable, trade, net of allowance


14,548


21,845Accounts receivable, joint interest owners and other, net of allowance


5,689


14,460Deferred tax asset





5,818Derivative financial instruments


15,407


619Other current assets


4,591


4,079Total current assets


48,710


53,984PROPERTY AND EQUIPMENT, Netfull cost method of accounting for oil and natural gas properties (including unevaluated costs of
$16.4 million and $34.9 million at December 31, 2008 and 2007, respectively)


307,059


717,290OTHER ASSETS


1,828


3,231TOTAL ASSETS

$
357,597

$
774,505LIABILITIES AND STOCKHOLDERS' EQUITYCURRENT LIABILITIES:Accounts payable, trade

$
3,086

$
7,665Accrued liabilities


8,779


29,616Derivative financial instruments





12,846Accrued interest payable


579


1,006Current portion of debt


239,000


Asset retirement obligation


547


589Total current liabilities


251,991


51,722ASSET RETIREMENT OBLIGATIONlong-term


6,011


6,045DERIVATIVE FINANCIAL INSTRUMENTSlong-term





102DEFERRED TAX LIABILITYlong-term





21,326OTHER NON-CURRENT LIABILITIES


102


534DELIVERY COMMITMENT


2,005


LONG-TERM DEBT





260,000Total liabilities


260,109


339,729COMMITMENTS AND CONTINGENCIES (Note 15)STOCKHOLDERS' EQUITYPreferred stock, $0.01 par value; 5,000,000 shares authorized; 2,875,000 issued and outstanding at December 31, 2008 and 2007


29


29Common stock, $0.01 par value; 60,000,000 shares authorized; 28,833,546 and 28,544,160 shares issued and outstanding at December 31, 2008 and 2007,
respectively


288


285Additional paid-in capital


423,951


421,808Retained earnings (deficit)


(326,780
)

12,654Total stockholders' equity


97,488


434,776TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY

$
357,597

$
774,505


See accompanying notes to the consolidated financial statements.

F-3

---





Table of Contents



EDGE PETROLEUM CORPORATION        CONSOLIDATED STATEMENTS OF OPERATIONS

Year Ended December 31,2008

2007

2006(in thousands, except share data)OIL AND NATURAL GAS REVENUE:Oil and natural gas sales

$
159,754

$
174,838

$
120,014Gain (loss) on derivatives


(977
)

(13,938
)

9,730Total revenue


158,777


160,900


129,744OPERATING EXPENSES:Oil and natural gas operating expenses including severance and ad valorem taxes


26,576


30,196


18,257Depletion, depreciation, amortization and accretion


88,341


91,718


61,080Impairment of oil and natural gas properties


362,851





96,942General and administrative expenses


16,776


17,494


13,788Total operating expenses


494,544


139,408


190,067OPERATING INCOME (LOSS)


(335,767
)

21,492


(60,323
)OTHER INCOME (EXPENSE):Interest expense, net of amounts capitalized


(11,787
)

(10,589
)

(2,500
)Amortization of deferred loan costs


(1,403
)

(977
)

(165
)Other income


289


379


152INCOME (LOSS) BEFORE INCOME TAXES


(348,668
)

10,305


(62,836
)INCOME TAX (EXPENSE) BENEFIT


15,778


(3,733
)

21,575NET INCOME (LOSS)


(332,890
)

6,572


(41,261
)Preferred Stock Dividends


(6,544
)

(7,577
)

NET LOSS TO COMMON STOCKHOLDERS

$
(339,434
)
$
(1,005
)
$
(41,261
)BASIC LOSS PER SHARE

$
(11.89
)
$
(0.04
)
$
(2.38
)DILUTED LOSS PER SHARE

$
(11.89
)
$
(0.04
)
$
(2.38
)BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING


28,682


27,613


17,368DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING


28,682


27,613


17,368


See
accompanying notes to the consolidated financial statements.

F-4

---





Table of Contents



EDGE PETROLEUM CORPORATION        CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

Year Ended December 31,2008

2007

2006(in thousands)NET INCOME (LOSS)

$
(332,890
)
$
6,572

$
(41,261
)Preferred Stock Dividends


(6,544
)

(7,577
)

NET LOSS TO COMMON STOCKHOLDERS


(339,434
)

(1,005
)

(41,261
)OTHER COMPREHENSIVE INCOME (LOSS), net of tax:Change in fair value of outstanding hedging and derivative instruments, net of income taxes








Reclassification of hedging and derivative losses(1)








1,713Other comprehensive income








1,713COMPREHENSIVE LOSS

$
(339,434
)
$
(1,005
)
$
(39,548
)(1) net of income taxes

$


$


$
922


See
accompanying notes to the consolidated financial statements.

F-5

---





Table of Contents



EDGE PETROLEUM CORPORATION        CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31,2008

2007

2006(in thousands)CASH FLOWS FROM OPERATING ACTIVITIES:Net income (loss)

$
(332,890
)
$
6,572

$
(41,261
)Adjustments to reconcile net income (loss) to net cash provided by operating activities:Unrealized (gain) loss on the fair value of derivatives


(27,735
)

17,516


(5,031
)Loss on property


34





Depletion, depreciation, amortization and accretion


88,341


91,718


61,080Impairment of oil and natural gas properties


362,851





96,942Gain on ARO settlement


(83
)




Amortization of deferred loan costs


1,403


977


165Deferred income taxes


(15,513
)

3,947


(21,626
)Share-based compensation cost


2,146


3,912


2,807Bad debt expense


90


257


Changes in operating assets and liabilities:(Increase) decrease in accounts receivable, trade


7,219


(4,364
)

7,242(Increase) decrease in accounts receivable, joint interest owners


8,759


(12,243
)

(117
)(Increase) decrease in other assets


18


(856
)

(442
)Increase (decrease) in accounts payable, trade


(4,579
)

3,712


(1,618
)Increase (decrease) in accrued interest payable


(427
)

465


524Increase (decrease) in accrued liabilities


(8,472
)

11,256


(1,256
)Increase in other liabilities


1,573





Net cash provided by operating activities


82,735


122,869


97,409CASH FLOWS FROM INVESTING ACTIVITIES:Oil and natural gas property and equipment additions


(60,157
)

(142,393
)

(144,338
)Drilling advances


(560
)

462


2,869Proceeds from the sale of oil and natural gas properties


19,203


1,302


628Acquisition of assets in January 2007





(375,197
)

Acquisition of Cinco Energy Corporation, net of cash acquired








429Overhedge derivative settlements


(10,643
)




Net cash used in investing activities


(52,157
)

(515,826
)

(140,412
)CASH FLOWS FROM FINANCING ACTIVITIES:Borrowings from long-term debt





275,000


62,000Repayments on long-term debt


(21,000
)

(144,000
)

(18,000
)Preferred dividends paid


(8,266
)

(5,855
)

Proceeds of preferred stock offering





143,750


Costs of preferred stock offering





(5,315
)

Proceeds of common stock offering





144,756


Costs of common stock offering





(6,665
)

Net proceeds from issuance of common stock





42


576Deferred loan costs





(3,674
)

(158
)Net cash provided by (used in) financing activities


(29,266
)

398,039


44,418NET INCREASE IN CASH AND CASH EQUIVALENTS


1,312


5,082


1,415CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR


7,163


2,081


666CASH AND CASH EQUIVALENTS, END OF YEAR

$
8,475

$
7,163

$
2,081


See accompanying notes to the consolidated financial statements.

F-6

---





Table of Contents



EDGE PETROLEUM CORPORATION        CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

Preferred Stock

Common Stock





Accumulated
Other
Comprehensive
Income (Loss)Additional
Paid-In
Capital

Retained
Earnings
(Deficit)

Total
Stockholders'
EquityShares

Amount

Shares

Amount(in thousands)BALANCE, DECEMBER 31, 2005




$



17,217

$
172

$
137,842

$
55,454

$
(1,713
)
$
191,755Issuance of common stock








225


2


1,404








1,406Compensation costrestricted stock














1,908








1,908Compensation costrepriced options














69








69Tax benefit associated with exercise of non-qualified stock options














462








462Change in valuation of hedging instruments




















1,713


1,713Net loss

















(41,261
)




(41,261
)BALANCE, DECEMBER 31, 2006








17,442


174


141,685


14,193





156,052Issuance of preferred stock


2,875


29








143,721








143,750Costs of preferred stock offering














(5,315
)







(5,315
)Issuance of common stock








10,925


109


144,647








144,756Costs of common stock offering














(6,665
)







(6,665
)Issuance of common stock








177


2


548








550Stock based compensation costs














3,404








3,404Tax benefit associated with exercise of non-qualified stock options














(217
)







(217
)Adoption of FIN 48

















(534
)




(534
)Preferred stock dividends ($0.71875 per share)

















(7,577
)




(7,577
)Net income

















6,572





6,572BALANCE, DECEMBER 31, 2007


2,875

$
29


28,544

$
285

$
421,808

$
12,654

$


$
434,776Issuance of common stock








289


3


592








595Stock based compensation costs














1,551








1,551Preferred stock dividends ($0.71875 per share)

















(6,544
)




(6,544
)Net loss

















(332,890
)




(332,890
)BALANCE, DECEMBER 31, 2008


2,875

$
29


28,833

$
288

$
423,951

$
(326,780
)
$


$
97,488


See accompanying notes to the consolidated financial statements.

F-7

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Table of Contents



EDGE PETROLEUM CORPORATION        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION, NATURE OF OPERATIONS AND GOING CONCERN UNCERTAINTY

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

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

Financial and Strategic Alternatives ProcessIn late 2007, the Company announced the hiring of a financial advisor to assist its Board of
Directors
with an assessment of strategic alternatives. On February 7, 2008, the Company provided an update on the strategic alternative process and publicly announced that it would implement a process
to explore a merger or sale of the Company. As a result of the strategic alternatives process, on July 15, 2008, the Company and Chaparral Energy, Inc. ("Chaparral"), a privately held
company, announced that they had entered into a definitive merger agreement that provided for Chaparral to acquire Edge in an all-stock transaction. To provide additional funding for the
transaction, Chaparral expected to sell 1.5 million shares of its Series B convertible preferred stock, par value $0.01 per share for $150 million in a private sale to Magnetar
Financial LLC, on behalf of itself and one or more of its affiliates and assigns (collectively, "Magnetar").

The
credit crisis and related turmoil in the global financial system and economic recession in the U.S. during the fourth quarter of 2008, along with declines in commodity prices and our
stock prices, created a challenging environment for the successful completion of our proposed merger with Chaparral. On December 17, 2008, the Company announced the termination of the Chaparral
merger agreement after both the Company and Chaparral determined it was highly unlikely that the conditions to the closing of the proposed merger would be satisfied or that Chaparral would be able to
obtain sufficient debt and equity financing to allow them to complete the proposed merger and operate as a

F-8

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. ORGANIZATION, NATURE OF OPERATIONS AND GOING CONCERN UNCERTAINTY (Continued)

combined
company, particularly in light of the challenging environment in the financial markets and the energy industry. As a result, after consultation with its legal and financial advisors, the
Company's Board of Directors approved a merger termination agreement with Chaparral and a termination and settlement agreement among Edge, Chaparral and Magnetar. Pursuant to the termination
agreements, Magnetar reimbursed Chaparral $5.0 million for certain expenses, of which $1.5 million was paid to the Company at Chaparral's direction, of which the Company paid
$0.3 million to its then-financial advisor, Merrill Lynch.

Going ConcernIn addition to the Deficiency under our Revolving Facility (defined in Note 11) created by the recent borrowing base
redetermination (see discussion in Notes 11 and 12), the capital expenditures required to maintain and/or grow production and reserves are substantial. The
Company's stock price has significantly declined over the past year which makes it more difficult to obtain equity financing on acceptable terms to address our liquidity issues. In addition, the
Company is reporting negative working capital at December 31, 2008 and a third consecutive year of net losses for the year ended December 31, 2008, which is largely the result of
impairments of the Company's oil and natural gas properties. Therefore, there is substantial doubt as to the Company's ability to continue as a going concern for a period longer than the current
fiscal year. The Company's ability to continue as a going concern is dependent upon the success of its financial and strategic alternatives process, which may include the sale of some or all of our
assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company. Until the possible completion of the financial and strategic alternatives
process, the Company's future remains uncertain and there can be no assurance that its efforts in this regard will be successful.

The
accompanying consolidated financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which implies that the
Company will continue to meet its obligations and continue its operations for the next twelve months. Realization values may be substantially different from carrying values as shown, and these
consolidated financial statements do not include any adjustments relating to the recoverability or classification of recorded asset amounts or the amount and classification of liabilities that might
be necessary as a result of this uncertainty.

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.

Cash and Cash EquivalentsThe Company considers all highly liquid investments with original maturities of three months or less to be cash
equivalents.

Financial InstrumentsThe Company's financial instruments consist of cash, receivables, payables, long-term debt and oil and natural gas
commodity derivatives. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of these items. The carrying

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

amount
of long-term debt as of December 31, 2008 and 2007 approximates fair value because the interest rates are variable and reflective of market rates. Derivative instruments are
reflected at fair value based on quotes obtained from the Company's counterparties.

Revenue Recognition and Gas Balancing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 typically not significantly different from the Company's share of production. But gas imbalances can occur when sales
are more or less than the Company's entitled ownership percentage of total gas production. Gas imbalances may be accounted for under either the (1) entitlements method, whereby revenue is
recorded on the Company's interest in the gas production actually sold or (2) sales method, whereby revenue is recorded on the basis of total gas actually sold by the Company. The Company uses
the sales method of accounting for gas balancing and an asset or a liability is recognized to the extent that there is a material imbalance in excess of the remaining gas reserves on the underlying
properties. As of December 31, 2008 and 2007, the Company's gas production was materially in balance, i.e. its cumulative portion of gas production taken and sold from wells in which the
Company has an interest was not materially different from the Company's entitled interest in gas production from those wells.

Delivery CommitmentsDuring 2007, the Company executed a gas gathering and compression services agreement with Frontier Midstream, LLC
("Frontier"). Following execution of such agreement, Frontier expedited the installation of the Rose Bud system in White County, Arkansas, including the high and low pressure gathering lines,
dehydration, compression and the interconnect with Ozark, in order to accommodate the Company's desire to be able to deliver natural gas as soon as its wells were completed. At the time of signing the
contract, the Company had completed and tested two productive wells in the Moorefield shale. The Rose Bud system was installed, operational and ready to receive the Company's production in June 2007.
The contract minimum commitment to Frontier is 2.7 Bcf over a three-year period for the pipeline interconnect. This line carries a $0.29 per
Mcf deficiency rate, for a total commitment for the pipeline of approximately $0.8 million. The Company has delivered approximately $63,800 of this commitment through December 31, 2008.
In addition to the pipeline, Frontier also built and installed lateral gathering lines to eight locations. The remaining commitment on these laterals is $1.3 million, for a total potential
liability of approximately $2.0 million to be paid by June 2010 if the minimum volumes are not delivered. The Company recorded a long-term liability for the aggregate amount of
$2.0 million in the fourth quarter of 2008. Although the Company believes there is the potential to develop this area and increase production, it does not currently have sufficient liquidity to
ensure that this occurs in the timeframe required by the gas gathering and compression services agreement with Frontier.

During
2008, the Company executed a gas gathering and compression services agreement with Integrys Energy Services ("Integrys") related to the construction and installation of a pipeline
connecting the Company's Slick State properties to its Bloomberg properties in order to secure more advantageous plant processing, transportation and gathering fees and access to gas markets. The
pipeline system was installed, operational and ready to redirect the production in September 2008. The contract minimum commitment to Integrys is approximately 11.2 Bcf over a three year period for
the pipeline interconnect. The amount of total commitment is $550,000 plus 8% interest per annum, for a total liability of approximately $0.6 million. The Company has delivered approximately
$71,400 of this commitment through December 31, 2008. The Company has not recorded a liability for this

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

commitment
as it expects to meet the minimum physical delivery based on estimated anticipated production.

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

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

InventoriesInventories consisting principally of tubular goods and production equipment, stated at the lower of weighted-average cost or market,
are
included in Other Current Assets on the consolidated balance sheet.

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

Oil and Natural Gas PropertiesThe accounting for our business is subject to special accounting rules that are unique to the oil and natural gas
industry. There are two allowable methods of accounting for oil and natural gas business activities: (1) the successful-efforts method and (2) the full-cost method. There are
several significant differences between these methods. Among these differences is that, under the successful-efforts method, costs such as geological and geophysical ("G&G"), exploratory dry holes and
delay rentals are expensed as incurred whereas under the full-cost method these types of charges are capitalized to their respective full-cost pool. The Company utilizes the
full-cost method of accounting for oil and natural gas properties. In accordance with the full-cost method of accounting, all costs associated with the exploration, development
and acquisition of oil and natural gas properties, including salaries, benefits and other internal costs directly attributable to these activities are capitalized. The Company's oil and natural gas
properties are located within the United States of America, which constitutes one cost center. The Company capitalized $4.1 million, $4.0 million, and $3.0 million of general and
administrative costs in 2008, 2007 and 2006, respectively. The Company also capitalizes a portion of interest expense on borrowed funds related to unproved oil and gas properties. The Company
capitalized approximately $2.6 million, $7.9 million, and $5.3 million of interest costs in 2008, 2007 and 2006, respectively.

In
the measurement of impairment of proved oil and natural gas properties, the successful-efforts method of accounting follows the guidance provided in SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived
Assets, where the first measurement for impairment is to compare the net book value
of the related asset to its undiscounted future cash flows using commodity prices consistent with management expectations. The full-cost method follows guidance provided in Securities and
Exchange Commission ("SEC") Regulation S-X Rule 4-10, where impairment is determined by the "ceiling test," whereby to the extent that such capitalized costs
subject to amortization in the full-cost pool (net of

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

depletion,
depreciation and amortization, prior impairments and related tax effects) 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 expense. Once incurred, an impairment of oil and natural gas properties is not reversible at a later date. A ceiling test
impairment could result in a significant loss for a reporting period; however, future depletion expense would be correspondingly reduced. In accordance with SEC Staff Accounting Bulletin ("SAB")
No. 103,Update of Codification of Staff Accounting Bulletins, derivative instruments qualifying as cash flow hedges are to be included in the
computation of limitation on capitalized costs. The Company has applied the mark-to-market accounting method of accounting since January 1, 2006;
therefore, the ceiling tests at December 31, 2008, 2007 and 2006 were not impacted by the fair value of our derivatives.

Impairment
of oil and natural gas properties is assessed quarterly in conjunction with the Company's quarterly and annual SEC filings. The Company recorded a non-cash ceiling
test impairment of oil and natural gas properties of $129.5 million ($84.2 million, net of tax) and $233.3 million ($215.8 million, net of tax) during the quarters ended
September 30 and December 31, 2008, respectively, as a result of declines in commodity prices and negative revisions in the Company's proved reserve quantities. For the third and fourth
quarters of 2007, the Company elected to use a pricing date subsequent to the balance sheet date, as allowed by SEC guidelines, to calculate the full-cost ceiling. As a result, no ceiling
test impairment was required at September 30 or December 31, 2007. Subsequent pricing did not, however, eliminate the ceiling test impairments calculated at September 30 and
December 31, 2008. The Company recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2006 of $96.9 million
($63.0 million, net of tax), during the third quarter of 2006, as a result of a decline in natural gas prices at the measurement date.

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 $16.4 million and $34.9 million at December 31, 2008 and 2007, 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 accordance with SAB No. 106,Interaction of Statement 143 and the Full Cost Rules,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, 2008, 2007 and 2006 were $5.08, $3.77, and $3.51, respectively.

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

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

Income TaxesThe Company accounts for income taxes under the provisions of SFAS No. 109,Accounting for Income
Taxes, which provides for an asset and liability approach to accounting for income taxes. Effective January 1, 2007, the Company also applied the provisions of Financial
Accounting Standards Board ("FASB") Interpretation No. 48,Accounting for Uncertainty in Income Taxes (an interpretation of FASB Statement
No. 109)("FIN 48"), and FASB Staff Position No. FIN 48-1,Definition of Settlement in FASB Interpretation
No. 48("FSP FIN 48-1"). FIN 48 clarified the accounting for uncertainty in income taxes recognized in the financial statements by prescribing
a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on de-recognitions, classification,
interest and penalties, accounting in interim periods, disclosure and transition. FSP FIN 48-1 provides that a company's tax position will be considered settled if the taxing
authority has completed its examination, the company does not plan to appeal, and it is remote that the taxing authority would reexamine the tax position in the future (see Note 17).

Earning per ShareThe Company accounts for earnings per share in accordance with SFAS No. 128,Earnings per
Share, which establishes the presentation requirements for earnings per share ("EPS") (see Note 19).

Share-Based CompensationAt December 31, 2008, the Company had a share-based employee compensation plan that included restricted stock units
and stock options issued to employees and non-employee directors, as more fully described in Note 19. Stock options were last issued in April 2004. The Company accounts for
share-based compensation in accordance with the provisions of SFAS No. 123(R),Share-Based Payment,which requires that the compensation cost
relating to share-based payment transactions be recognized in financial statements. The Company elected to use the modified-prospective method for adoption of SFAS No. 123(R) and recognized
additional compensation expense of $68,937 in 2006. No further expense associated with stock options was recorded in 2007 or 2008 or is expected to be recognized unless future awards are granted. The
Company has recorded compensation expense associated with the issuance of restricted stock and restricted stock units since the plan was adopted in 1997 and stock or stock units were first granted.

Share-based
compensation for the years ended December 31, 2008, 2007 and 2006 was approximately $1.6 million, $3.0 million and $2.0 million, respectively, of
which $1.2 million, $2.4 million and $1.6 million, respectively, is included in general and administrative expenses ("G&A") and $0.4 million, $0.6 million and
$0.4 million, respectively is capitalized to oil and natural gas properties.

During
the year ended December 31, 2008, 1,600 restricted stock units ("RSUs") were granted. At December 31, 2008, there were 305,020 RSUs outstanding, all of which are
classified as equity instruments. No options were granted during the year ended December 31, 2008. During 2008, no

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

options
were exercised or forfeited, resulting in 643,600 vested unexercised options outstanding at period end.

Fair Value MeasurementsEffective January 1, 2008, the Company partially adopted SFAS No. 157,Fair Value
Measurements,which provides a common definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements, but does
not require any new fair value measurements. The partial adoption of SFAS No. 157 had no impact on the Company's consolidated financial statements, but it did result in additional required
disclosures as set forth in Note 10. In February 2008, the FASB issued FSP 157-2,Effective Date of FASB Statement No. 157,
which delays the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value
in the financial statements on a recurring basis (at least annually). Accordingly, the Company has not yet applied the provisions of SFAS No. 157 to its AROs.

In
conjunction with the adoption of SFAS No. 157, the Company also adopted SFAS No. 159,The Fair Value Option for Financial Assets and Financial
LiabilitiesIncluding an Amendment of FASB Statement No. 115,effective January 1, 2008. SFAS No. 159 allows a company the option to value its
financial assets and liabilities, on an instrument by instrument basis, at fair value, and include the change in fair value of such assets and liabilities in its results of operations. The Company did
not apply the provisions of SFAS No. 159 to any of its financial assets or liabilities. Accordingly, there was no impact to the Company's consolidated financial statements resulting from the
adoption of SFAS No. 159.

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

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

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

Concentration of Credit RiskSubstantially all of the Company's accounts receivable result from oil and natural gas sales or joint interest
billings
to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk in that these entities may be similarly
affected by changes in economic and other conditions. Historically, the Company has not experienced significant credit losses on such receivables; however, in 2001, the Company reserved
$0.5 million related to non-payments from two purchasers of the Company's oil and natural gas, of which $0.3 million was written off and $0.2 million was recovered
during 2007. In 2008, the Company expensed approximately $0.1 million in accounts receivable from joint interest owners. In 2007, the Company expensed $0.5 million in accounts
receivable, trade related to the ongoing Golden Prairie dispute that the Company no longer felt it could collect as it had exhausted its efforts on this matter. In 2006, the Company wrote off $1,571
in accounts receivable from joint interest owners. The Company cannot ensure that similar such losses may not be realized in the future.

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

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

In
March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activitiesan amendment of FASB Statement
No. 133("SFAS No. 161"). SFAS No. 161 requires entities to provide enhanced disclosures about (a) how and why an entity uses derivative
instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and (c) how derivative instruments and
related hedged items affect an entity's financial position, financial performance, and cash flows. SFAS No. 161 is effective for annual periods beginning on or after November 15, 2008.
Early application of SFAS No. 161 is encouraged, as are comparative disclosures for earlier periods at initial adoption. The Company will adopt SFAS No. 161 on January 1, 2009 and
does not expect adoption of this statement to impact its consolidated financial statements, but it does expect it to impact disclosures made in its future quarterly and annual filings.

In
December 2008, the SEC issued the final rule,"Modernization of Oil and Gas Reporting," which adopts revisions to the SEC's oil and
natural gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. Early adoption of the new
rules is prohibited. The new rules are intended to provide investors with a more meaningful and comprehensive understanding of oil and natural gas reserves to help investors evaluate their investments
in oil and natural gas companies. The new rules are also designed to modernize the oil and natural gas disclosure requirements to align them with current practices and changes in technology. The new
rules include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves and permitting
disclosure of probable and possible reserves. The Company is currently evaluating the potential impact of these rules. The SEC is discussing the rules with the FASB staff to align FASB accounting
standards with the new SEC rules. These discussions may delay the required compliance date. Absent any change in the effective date, the Company will begin complying with the disclosure requirements
in our annual report on Form 10-K for the year ended December 31, 2009.

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

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Below are the components of Accounts Receivable, Joint Interest Owners and Other, as of December 31, 2008 and 2007:

December 31,2008

2007(in thousands)Joint interest owners

$
5,178

$
14,156Other receivables(1)


526


307Allowance for doubtful accounts receivable (joint interest owners)


(15
)

(3
)Accounts receivable, joint interest owners and other, net of allowance

$
5,689

$
14,460


---

The
following table sets forth changes in the Company's allowance for doubtful accounts receivable, trade and joint interest owners and other, for the years ended December 31,
2008, 2007 and 2006:

Balance at
Beginning of
Year

Charged to
Costs and
Expenses

Deductions
and Other

Balance at
End of
Year(in thousands)Year ended December 31, 2008:Allowance for doubtful accounts

$
3

$
90

$
(13
)
$
80Year ended December 31, 2007:Allowance for doubtful accounts

$
528

$
257

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

$
530

$


$
(2
)
$
528


4. OTHER CURRENT ASSETS

Below are the components of other current assets as of December 31, 2008 and 2007:

December 31,2008

2007(in thousands)Prepaid insurance

$
1,003

$
785Prepayments and deposits to vendors


378


433Prepaid seismic licenses





469Drilling advances


1,515


485Federal tax deposit


449


225Inventory(1)


1,246


1,682Other current assets

$
4,591

$
4,079






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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



5. PROPERTY AND EQUIPMENT

At December 31, 2008 and 2007, property and equipment consisted of the following:

December 31,2008

2007(in thousands)Developed oil and natural gas properties

$
1,118,774

$
1,059,788Unevaluated oil and natural gas properties


16,432


34,865Computer equipment and software


5,113


5,085Other office property and equipment


5,997


5,996Total property and equipment


1,146,316


1,105,734Accumulated depletion, depreciation and amortization and impairments


(839,257
)

(388,444
)Property and equipment, net

$
307,059

$
717,290


Costs
associated with unproved properties and major development projects related to continuing operations of $16.4 million and $34.9 million as of December 31, 2008
and 2007, respectively, are excluded from amounts subject to amortization.

Year Costs IncurredExcluded
Costs at
December 31,
2008Prior
Years

2006

2007

2008(in thousands)Property acquisition

$
979

$
1,548

$
2,296

$
3,079

$
7,902Exploratory


108


3,105


1,619


2,169


7,001Capitalized interest


20


239


598


672


1,529Total Costs Excluded

$
1,107

$
4,892

$
4,513

$
5,920

$
16,432


The
majority of the evaluation activities are expected to be completed within two to three years, subject to the Company's ability to obtain financing to increase its severely limited
capital budget (see Note 11). These excluded costs represent unproved properties and major development projects in which the Company owns a direct interest, including the
following:



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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. PROPERTY AND EQUIPMENT (Continued)



6. ACQUISITIONS AND DIVESTITURES

South and southeast Texas asset acquisition in January 2007On November 16, 2006, the Company entered into two separate purchase and sale
agreements (both of which were subsequently amended) with an unrelated privately held company for ownership interests in certain leasehold acreage, oil and natural gas properties located in southeast
and south Texas, consisting of producing wells from the private company and eight other owners who transferred their interests to the private company prior to the closing, option and leasehold rights
and exploration and development rights in an exploration project area known as the Mission project area in south Texas, and certain gathering facilities and ownership of approximately 13 miles
of natural gas gathering pipelines and related infrastructure serving certain producing assets in southeast Texas (the "January 2007 Acquisition"). In addition, as part of this acquisition, the
Company acquired a working interest, option and leasehold rights in two exploration ventures in separate areas, primarily in Texas, from the private company for $10.0 million. Closing occurred
on January 31, 2007, accordingly, the Company's consolidated results of operations include the acquired properties in south and southeast Texas beginning February 1, 2007. On
December 12, 2007 the Company accepted the final adjusted closing price of $384.4 million, which was adjusted pursuant to the post-closing adjustment provisions of the
amended purchase and sale agreements. The Company financed the purchase price of the January 2007 Acquisition through public offerings of common and preferred stock (see Notes 13 and
14) and borrowings under its Revolving Facility (see Note 11). The Company also capitalized approximately $1.4 million in other direct costs resulting from the acquisition and
assumed ARO liabilities of $0.9 million.

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

The
following unaudited pro forma results for the year ended December 31, 2007 show the effect on the Company's consolidated results of operations as if the January 2007
Acquisition had occurred on January 1, 2007. The following unaudited pro forma results for the year ended December 31, 2006 show the effect on the Company's consolidated results of
operations as if the January 2007 Acquisition had occurred on January 1, 2006. The pro forma results for the 2007 and 2006 periods presented are the result of combining the statement of income
for the Company with the revenues and direct operating expenses of the properties acquired adjusted for (1) assumption of ARO liabilities and

F-19

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. ACQUISITIONS AND DIVESTITURES (Continued)

accretion
expense for the properties acquired, (2) depletion expense applied to the adjusted basis of the properties acquired using the purchase method of accounting, (3) depreciation
expense for other non-oil and natural gas assets acquired, (4) interest expense on added borrowings necessary to finance the acquisition, (5) amortization of deferred loan
costs for new loan costs related to the financing of the acquisition, (6) dividends payable on the 5.75% Series A cumulative convertible perpetual preferred stock, (7) the related
income tax effects of these adjustments based on the applicable statutory rates, and (8) the impact of common and preferred shares issued in public offerings completed to partially finance the
January 2007 Acquisition. The pro forma information is based upon numerous assumptions, and is not necessarily indicative of future results of operations:

For the Year Ended
December 31,2007

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

$
166,737

$
213,743Net income (loss)


8,324


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


90


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

$


$
(1.15
)Diluted

$


$
(1.15
)


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

DivestituresDuring 2008, the Company completed sales of certain non-core assets, which included a pipeline and approximately 120
properties in Texas and Mississippi, to various buyers for aggregate proceeds of approximately $19.2 million. During January 2007, the Company divested a portion of its interest in a Louisiana
well for $1.1 million. In 2006, the Company consummated the divestiture of its Buckeye properties located in Live Oak County, Texas for net proceeds of $0.6 million. Under full cost
accounting rules, gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between
capitalized costs and proved reserves of oil and natural gas attributable to a country. Dispositions during 2008, 2007 and 2006 did not significantly alter the relationship between capitalized costs
and proved reserves; therefore, the proceeds from these transactions were recognized as an adjustment of capitalized costs.

7. ASSET RETIREMENT OBLIGATIONS

SFAS No. 143 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,

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. ASSET RETIREMENT OBLIGATIONS (Continued)

excluding
salvage values, are initially recorded, the carrying amount of the related oil and natural 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, and the Company records an abandonment liability associated with its oil and natural gas wells when those assets are
placed in service. The changes to the ARO during the periods ended December 31, 2008 and 2007 are as follows:

For the Year Ended
December 31,2008

2007(in thousands)ARO, beginning of year

$
6,634

$
3,371Additional liabilities incurred


744


1,203Liabilities settled


(1,317
)

(53
)Accretion expense


379


297Revisions


118


1,816ARO, end of year

$
6,558

$
6,634Current portion

$
547

$
589Long-term portion

$
6,011

$
6,045


ARO
liabilities incurred during the year ended December 31, 2008 include obligations assumed for 54 properties that were successfully drilled during the year and several
non-operated properties that were not previously identified. Liabilities settled during the year ended December 31, 2008 included 135 properties that were either plugged or sold.
Revisions to the estimated liability relate to changes in working interests in certain properties.

8. ACCRUED LIABILITIES

Below are the components of accrued liabilities as of December 31, 2008 and 2007:

As of December 31,2008

2007(in thousands)Accrued capital expenditures

$
2,371

$
8,084Professional services


1,408


1,368Royalties payable


3,344


12,377Lease operating expenses including ad valorem taxes payable


1,119


4,291Preferred stock dividends payable





1,722Other


537


1,774Accrued liabilities

$
8,779

$
29,616


F-21

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. HEDGING AND DERIVATIVE ACTIVITIES

Due to the volatility of oil and natural gas prices, the Company periodically enters into price-risk management transactions (e.g., swaps, collars and floors) for a
portion of its expected oil and natural gas production to seek to achieve a more predictable 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 is also intended to reduce the Company's potential exposure to significant price declines. As a result of
changes to the Company's 2008 production and the impact of certain divestitures, both of which reduced expected production as compared to that expected at the time the Company entered into the
derivative contracts, the Company had approximately 115% and 190% of its 2008 natural gas and crude oil production, respectively,
covered by derivative contracts. The Company's arrangements, to the extent it enters into any, are intended to apply to only a portion of its expected production and thereby provide only partial price
protection against declines in oil and natural gas prices. None of these instruments were, at the time of their execution, intended to be used for trading or speculative purposes, but a portion of
these instruments was subsequently deemed as such because of the decrease in the Company's 2008 production. These derivative transactions are generally placed with major financial institutions that
the Company believes are financially stable; however, in light of the recent global financial crisis, there can be no assurance of the foregoing. 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 reviews the Company's policies and trades monthly.

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

During
the first quarter of 2006, the Company began to apply mark-to-market accounting treatment to all outstanding derivative contracts, whereas cash flow hedge
accounting treatment was applied to natural gas contracts prior to 2006. As a result, the changes in fair value are not deferred through other comprehensive income, but rather recorded in revenue
immediately as unrealized gains

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. HEDGING AND DERIVATIVE ACTIVITIES (Continued)

or
losses. The Company continues to evaluate the terms of new contracts entered into to determine whether cash flow hedge accounting treatment or mark-to-market accounting
treatment will be applied. The Company has always used mark-to-market accounting treatment for its crude oil contracts.

For
the years ended December 31, 2008, 2007 and 2006, the Company included in revenue realized and unrealized losses related to its derivative contracts. For the three years ended
December 31, 2008, 2007 and 2006, the Company included in total revenue the following realized and unrealized gains and losses:

For the Year Ended December 31,2008

2007

2006(in thousands)Natural gas derivative realized settlements

$
(9,453
)
$
4,513

$
4,699Crude oil derivative realized settlements


(19,259
)

(935
)

Natural gas derivative unrealized change in fair value


10,765


(2,060
)

4,686Crude oil derivative unrealized change in fair value


16,970


(15,456
)

345Gain (loss) on derivatives

$
(977
)
$
(13,938
)
$
9,730


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

Fair Value of
Outstanding
Derivative Contracts
as of December 31,Transaction
Type





Price
Per Unit

Volumes
Per DayTransaction Date

Beginning

Ending

2008

2007(in thousands)Natural Gas(1):01/07

Collar

01/01/2008

12/31/2008

$7.50-$9.00

20,000 MMBtu

$



1,09601/07

Collar

01/01/2008

12/31/2008

$7.50-$9.00

10,000 MMBtu





61901/07

Collar

01/01/2008

12/31/2008

$7.50-$9.02

10,000 MMBtu





59904/07

Collar

01/01/2009

12/31/2009

$7.75-$10.00

10,000 MMBtu


6,688


12510/07

Collar

01/01/2009

12/31/2009

$7.75-$10.08

10,000 MMBtu


6,702


187Crude Oil(2):12/06

Swap

01/01/2008

12/31/2008

$66.00

1,500 Bbl





(14,541
)10/07

Collar

01/01/2009

12/31/2009

$70.00-$93.55

300 Bbl


2,017


(414
)$
15,407

$
(12,329
)


---

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. FAIR VALUE MEASUREMENTS

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants
at the measurement date (an exit price). Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are
not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the
instruments or market and the instruments' complexity.

Valuation Techniques

In accordance with SFAS No. 157, valuation techniques used for assets and liabilities accounted for at fair value are generally
categorized into three types:



The
three approaches described within SFAS No. 157 are consistent with generally accepted valuation methodologies. While all three approaches are not applicable to all assets or
liabilities accounted for at fair value, where appropriate and possible, one or more valuation techniques may be used. The selection of the valuation method(s) to apply considers the definition of an
exit price and the nature of the asset or liability being valued and significant expertise and judgment is required. For assets and liabilities accounted for at fair value, valuation techniques are
generally a combination of the market and income approaches. Accordingly, the Company aims to utilize valuation techniques that maximize the use of observable inputs and minimize the use of
unobservable inputs.

Input Hierarchy

SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value
directly related to the amount of subjectivity associated with the inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities
(Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy defined by SFAS No. 157 are as
follows:



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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. FAIR VALUE MEASUREMENTS (Continued)



Fair Value on a Recurring Basis

The following table sets forth by level within the fair value hierarchy the Company's financial assets and liabilities that were
accounted for at fair value on a recurring basis as of December 31, 2008. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the
lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may
affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

Fair Value Measurements Using:Total Fair
Value

Quoted
Prices in
Active
Markets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)(in thousands)Assets:Derivative instruments

$
15,407

$


$


$
15,407Liabilities:Derivative instruments

$


$


$


$



The
following table sets forth a reconciliation of changes in the fair value of the Company's derivative instruments classified as Level 3 in the fair value hierarchy.

Three Months Ended
December 31, 2008

Year Ended
December 31, 2008Assets

Liabilities

Assets

Liabilities(in thousands)Balance as of beginning of period

$
181

$
(4,107
)
$
619

$
(12,948
)Realized and unrealized gains included in earnings


14,516


2,675


16,835


39,613Realized and unrealized gains (losses) included in other comprehensive income











Settlements


710


1,432


(2,047
)

(26,665
)Transfers in and/or out of Level 3











Balance as of December 31, 2008

$
15,407

$


$
15,407

$
Change in unrealized losses relating to instruments still held as of December 31, 2008

$
(15,157
)
$


$
(15,509
)
$



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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. FAIR VALUE MEASUREMENTS (Continued)

Gains and losses (realized and unrealized) for Level 3 recurring items are included in total revenue on the consolidated statements of operations. Settlements represent cash
settlements of contracts during the period, which are included in total revenue on the consolidated statements of operations.

Transfers
in and/or out represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets
and liabilities that were
previously classified as Level 3 for which the lowest significant input became observable during the period. There were no transfers in or out of Level 3 during the periods presented.

Fair Value on a Nonrecurring Basis

In February 2008, the FASB issued FSP 157-2, which postpones the effective date of SFAS No. 157 for
non-financial assets and liabilities. Therefore, the Company has not adopted the provisions of SFAS No. 157 for its asset retirement obligations ("ARO"). The Company uses fair value
measurements on a nonrecurring basis in its AROs. These liabilities are recorded at fair value initially and assessed for revisions periodically thereafter. The lowest level of significant inputs for
fair value measurements for ARO liabilities are Level 3. A reconciliation of the beginning and ending balances of the Company's ARO is presented in Note 1, in accordance with SFAS
No. 143, and the Company expects to expand its disclosures regarding its ARO upon complete adoption of SFAS No. 157.

11. DEBT

On January 30, 2007, the Company entered into a Fourth Amended and Restated Credit Agreement (as amended, the "Revolving Facility") for a new revolving credit facility with Union
Bank of California ("UBOC"), as administrative agent and issuing lender, and the other lenders party thereto (together with UBOC, the "Lenders"). Pursuant to the Revolving Facility, UBOC acts as the
administrative agent for a senior first lien secured borrowing base revolving credit facility in favor of the Company and certain of its wholly-owned subsidiaries in an amount equal to
$750 million, of which only $320 million was available under the borrowing base at the time of closing. The Revolving Facility has a letter of credit sub-limit of
$20 million. The Revolving Facility's original maturity was scheduled for January 31, 2011. In connection with the Revolving Facility, the Company paid the Lenders fees in an amount
equal to 1.00% of the initial borrowing base, or $3.2 million, on January 31, 2007. The Company also paid approximately $0.6 million for certain other administrative fees, legal
fees, fronting fees and work fees in connection with the Revolving Facility. The aggregate fees of $3.8 million (of
which $0.1 million was paid in December 2006) were recorded to deferred loan costs and are being amortized over the maturity of the Revolving Facility.

At
December 31, 2008, borrowings under the Revolving Facility bore interest at either LIBOR plus an applicable margin ranging from 1.25% to 2.5% or Prime plus a margin of up to
0.25%, with an unused commitment fee ranging from 0.50% to 0.25%. At December 31, 2008, the interest rates applied to the Company's outstanding Prime and LIBOR borrowings were 3.75% and 4.33%,
respectively. As of December 31, 2008, $239 million in total borrowings were outstanding under the Revolving Facility. The borrowing base was reduced from $320 million to
$300 million during the fourth quarter of 2007 and the conforming borrowing base was reduced from $300 million to $250 million. In early May 2008, the Company's Revolving Facility
borrowing base and conforming borrowing base were redetermined by the Lenders and set at $250 million and $225 million,

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. DEBT (Continued)

respectively.
These reductions were primarily the result of the sale of certain non-core assets during the first quarter of 2008 and the reduction of total proved reserves as reported in
the year-end reserve reports of the Company's independent reserve engineers.

On
July 11, 2008, in connection with the proposed merger with Chaparral, the Company entered into a Consent Agreement (the "Chaparral Consent"). Pursuant to the Chaparral Consent
and subject to the terms thereof, the Lenders deferred their right to conduct a borrowing base redetermination on or before June 30, 2008 and agreed to conduct the redetermination on
October 31, 2008. The Company paid the Lenders a fee of approximately $0.4 million in connection with the deferral of the redetermination. On November 5, 2008, the Lenders agreed
to delay the interim redetermination from October 31, 2008 until November 15, 2008. In consideration for this deferral, the Lenders placed a restriction upon the borrowing base such that
it was effectively lowered to $240 million until the interim redetermination occurred. Pursuant to the terms of the Revolving Facility, upon completion of the redetermination, the Company's
borrowing base would also be the conforming borrowing base. This redetermination process was completed in January 2009 and the Lenders established a new borrowing base under the Revolving Facility of
$125 million, resulting in a deficiency of $114 million (the "Deficiency"). As required by the Revolving Facility, the Company elected to prepay the Deficiency in six equal monthly
installments, with the first $19 million installment being due on February 9, 2009. On February 9, 2009, the Company entered into a Consent and Agreement (the "February Consent")
among the Company and the Lenders deferring the payment date of the first $19 million installment until March 10, 2009, and extending the due date for each subsequent installment by one
month with the last of the six $19 million installment payments to be due on August 10, 2009. In connection with the February Consent, the Company agreed to prepay $5.0 million of
its outstanding advances under the Revolving Facility, in two equal installments. The first $2.5 million prepayment was paid on February 9, 2009 and the second $2.5 million
prepayment was paid on February 23, 2009 with each of the prepayments to be applied on a pro rata basis to reduce the remaining six $19 million deficiency payments. On March 10,
2009, the Company entered into a Consent and Agreement (the "March Consent") with the Lenders under the Revolving Facility, which provided, among other things, for the extension of the due date for
the first installment to repay the Deficiency from March 10, 2009 to March 17, 2009. Notwithstanding such extension, the Company agreed with the Lenders that each of the other five equal
installment payments required to eliminate the Deficiency would be due and payable as provided for in the February Consent.

On
March 16, 2009, the Company entered into an amended Consent and Agreement (the "Amended Consent") which provides, among other things, (1) that the Company will make a
$25 million payment on May 31, 2009 with all remaining principal, fees and interest amounts under the Revolving Facility to be due and payable on June 30, 2009, (2) that it
will be an event of default (i) if the Company fails to have executed and delivered on or before May 15, 2009 at least one of the following (a) a commitment letter from a lender
or group of lenders reasonably satisfactory to the Lenders providing for the provision by such lender or group of lenders of a credit facility in an amount sufficient to repay all of our obligations
under the Revolving Facility on or before June 30, 2009, (b) a merger agreement or similar agreement involving us as part of a transaction that results in the repayment of the Company's
obligations under the Revolving Facility on or before June 30, 2009, and (c) a purchase and sale agreement with a buyer or group of buyers reasonably acceptable to our Lenders providing
for a sale transaction by us that results in the repayment of all of the Company's obligations under the Revolving Facility on or before June 30, 2009, or (ii) if the Company is in
default

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. DEBT (Continued)

under
or its hedging arrangements have been terminated or cease to be effective without the prior written consent of its Lenders, (3) that the Company's advances under the Revolving Facility
will bear interest at a rate equal to the greater of (a) the reference rate publicly announced by Union Bank of California, N.A. for such day, (b) the Federal Funds Rate in effect
on such day plus 0.50% and (c) a rate determined by the Administrative Agent to be the Daily One-Month LIBOR (as defined in the Revolving Facility), in each case plus 2.5% or,
during the continuation of an event of default, plus 4.5% (resulting in an effective interest rate of approximately 5.75% as of March 16, 2009), (4) for limitations on the making of
capital expenditures and certain investments, and (5) for the elimination of the current ratio, leverage ratio and interest coverage ratio covenant requirment. The Amended Consent also
eliminates the six $19 million deficiency payments which were contemplated by the February Consent and the March Consent. To comply with the terms of the Amended Consent, the Company
anticipates that it will need to (i) sell select individual assets prior to May 31, 2009 to enable us to make the $25 million payment which is due on May 31, 2009, and/or
(ii) negotiate a commitment letter with a new lender or group of lenders prior to May 15, 2009 in an amount sufficient to repay all of the Company's obligations under the Revolving
Facility on or before June 30, 2009, and/or (iii) have negotiated the sale, merger or other business combination involving us which results in the repayment of all of the Company's
obligations under the Revolving Facility prior to May 15, 2009 and to have closed such transaction on or before June 30, 2009. The Amended Consent limits the making of capital
expenditures and the Company anticipates a severe curtailment of its drilling plans and other capital expenditures in 2009.

If
the Company breaches any of the provisions of the Amended Consent, its Lenders will be entitled to declare an event of default, at which point the entire unpaid principal balance of
the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, would become immediately due and payable. In any event, the entire unpaid principal balance of the
loans, together with all accrued and unpaid interest and other amounts then owing to the Lenders, will be payable on June 30, 2009 unless earlier paid or a further extension with respect to
payment is negotiated with the Lenders. The Lenders may take action to enforce their rights with respect to the outstanding obligations under the Revolving Facility. Because substantially all of the
Company's assets are pledged as collateral under the Revolving Facility, if the Lenders declare an event of default, they would be entitled to foreclose on and take possession of the Company's assets.
In such an event, the Company may be forced to liquidate or to otherwise seek protection under Chapter 11 of the U.S. Bankruptcy Code. These matters, as well as the other risk factors related
to the Company's liquidity and financial
position raise substantial doubt as to our ability to continue as a going concern (see Note 1). With respect to the Company's compliance with the Amended Consent, there can be no assurance that
the Company will be able to further negotiate the terms of the Amended Consent or negotiate a further restructuring of the related indebtedness or that it will be able to either make any required
payments when they become due. Moreover, there can be no assurance that the Company will be successful in its efforts to comply with the terms of the Amended Consent, including its ongoing efforts to
evaluate and assess our various financial and strategic alternatives (which may include the sale of some or all of our assets, a merger or other business combination involving the Company, or the
restructuring or recapitalization of the Company). If such efforts are not successful, the Company may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

The
Company's obligations under the Revolving Facility are secured by substantially all of the Company's assets. The Revolving Facility provides for certain restrictions, including, but
not limited to,

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. DEBT (Continued)

limitations
on additional borrowings, sales of oil and natural gas properties or other collateral, and engaging in merger or consolidation transactions. The Revolving Facility restricts dividends on
common stock and certain distributions of cash or properties and certain liens but no longer contains any financial covenants as a result of the Amended Consent.

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

12. SUBSEQUENT EVENTS

During January 2009, the Company announced that the Lenders to its Revolving Facility had completed their borrowing base redetermination and reduced the Company's borrowing base on its
Revolving Facility to $125 million, resulting in a $114 million borrowing base deficiency (see Note 11 above). On March 10, 2009, the Company entered into the March Consent
with the Lenders to its Revolving Facility (see Note 11 above). In addition, on March 16, 2009, the Company entered into the Amended Consent with the Lenders under the Revolving Facility
(see Note 11 above).

Also
in January 2009, the Company retained an investment banking firm to assist further in an evaluation of its strategic alternatives, including a capital restructuring for the Company.
Additionally, the Company has engaged a law firm to act as the Company's legal advisor in connection with the evaluation of its strategic alternatives and to represent the Company generally as primary
outside counsel in its ongoing corporate and securities matters. There can be no assurance that the Company will be successful in pursuing any strategic alternatives. Moreover, there can be no
assurance that the Company's ongoing efforts to evaluate and assess its various financial and strategic alternatives (which may include the sale of some or all of the Company's assets, a merger or
other business combination involving the Company, restructuring of the Company's debt or the issuance of additional equity or debt) will be successful. If such efforts are not successful, the Company
may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

Appointment of Chief Financial OfficerEffective as of January 26, 2009, the Board of Directors of the Company, appointed Gary L.
Pittman as Executive Vice President and Chief Financial Officer of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. SUBSEQUENT EVENTS (Continued)

the
Company. Mr. Pittman replaces the Company's Acting Chief Financial Officer, C.W. MacLeod, who will continue his role with the Company as Senior Vice President, Business Development
and Planning.

13. SHELF REGISTRATION STATEMENT

In the third quarter 2007, the SEC declared effective the Company's registration statement filed with the SEC that registered securities of up to $500 million of any combination
of debt securities, preferred stock, common stock, warrants for debt securities or equity securities of the Company and guarantees of debt securities by the Company's subsidiaries. Net proceeds, terms
and pricing of the offering of securities issued under the shelf registration statement will be determined at the time of the offerings. The shelf registration statement does not provide assurance
that the Company will or could sell any such securities. The Company's ability to utilize the shelf registration statement for the purpose of issuing, from time to time, any combination of debt
securities, preferred stock, common stock or warrants for debt securities or equity securities will depend upon, among other things, market conditions and the existence of investors who wish to
purchase the Company's securities at prices acceptable to the Company. As of March 11, 2009, the Company had $500 million available under its shelf registration statement. However,
because the aggregate market value of the Company's outstanding common stock is less than $75 million, the type and amount of any securities offering under the registration statement may be
limited.

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

Common Stock Offering

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

$
144,756

$
143,750Underwriting discount


(6,152
)

(4,672
)Other costs of offering


(513
)

(643
)Net Proceeds

$
138,091

$
138,435Shares issued


10,925


2,875Issue price

$
13.25

$
50.00


14. PREFERRED STOCK

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

Dividends.The Convertible Preferred Stock accumulates dividends at a rate of $2.875 for each share of Convertible Preferred
Stock per year.
Dividends are cumulative from the date of first issuance and, to the extent payment of dividends is not prohibited by the Company's debt agreements, assets are

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. PREFERRED STOCK (Continued)

legally
available to pay dividends and the Board of Directors or an authorized committee of the Board declares a dividend payable, the Company pays dividends in cash, every quarter. The first payment
was made on April 15, 2007 and the Company continued to make quarterly dividends payments through October 15, 2008. The Board did not declare a dividend in the fourth quarter of 2008 due
to the Company's current reduced liquidity. Cumulative dividends in arrears at December 31, 2008 amounted to $1.7 million.

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

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

Ranking.The Company's Convertible Preferred Stock ranks:



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

Optional redemption.If fewer than 15% of the shares of Convertible Preferred Stock issued in the January 2007 offering
(including any additional
shares issued pursuant to the underwriters' over-allotment option) are outstanding, the Company may, at any time on or after January 20, 2010, at its option, redeem for cash all
such Convertible Preferred Stock at a redemption price equal to the liquidation preference of $50.00 plus any accrued and unpaid dividends, if any, on a share of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. PREFERRED STOCK (Continued)

Convertible
Preferred Stock to, but excluding, the redemption date, for each share of Convertible Preferred Stock.

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

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

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

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

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



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. PREFERRED STOCK (Continued)



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

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

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



15. COMMITMENTS AND CONTINGENCIES

CommitmentsAt December 31, 2008, the Company was obligated under non-cancelable operating leases. Following is a schedule of the
remaining future minimum lease payments under these leases:

(in thousands)2009

$
1,1892010


1,1972011


1,1832012


1,1742013


683Total

$
5,426


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15. COMMITMENTS AND CONTINGENCIES (Continued)

Rent expense for the years ended December 31, 2008, 2007 and 2006 was approximately $1.1 million, $0.9 million, and $0.7 million, respectively.

As
described in Note 11, the Company has significant repayments of its outstanding debt due by June 30, 2009.

As
described in Note 2, the Company has natural gas delivery commitments to Frontier for which a liability of approximately $2.0 million was recorded in
long-term liabilities during the fourth quarter of 2008. The Company also has natural gas delivery commitments to Integrys for approximately $550,000 plus interest, but management believes
the Company can meet this delivery commitment based on estimated anticipated production.

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.

David Blake, et al. v. Edge Petroleum CorporationOn September 19, 2005, David Blake and David Blake, Trustee of the David and Nita Blake
1992
Children's Trust, filed suit against the Company in state district court in Goliad County, Texas alleging breach of contract for failure and refusal to transfer overriding royalty interests to
plaintiffs in several leases in the Nita and Austin prospects in Goliad County, Texas and failure and refusal to pay monies to Blake pursuant to such overriding royalty interests for wells completed
on the leases. The plaintiffs seek relief of (1) specific performance of the alleged agreement, including granting of overriding royalty interests by us to Blake; (2) monetary damages
for failure to grant the overriding royalty interests; (3) exemplary damages for his claims of business disparagement and slander; (4) monetary damages for tortious interference; and
(5) attorneys' fees and court costs. Venue of the case was transferred to Harris County, Texas by agreement of the litigants. The Company's subsidiaries, Edge Petroleum Exploration Company,
Edge Petroleum Operating Company and Edge Petroleum Production Company, were also added as defendants. The Company filed a counterclaim against plaintiff and joined various related entities that are
controlled by Blake, seeking lease interests in which the Company contends it had been wrongfully denied participation and also claiming that proprietary information was misappropriated. The parties
have moved for summary judgment on each other's claims and counterclaims, which the trial court has denied as to both sides. In November 2007, the Company filed a separate motion for summary judgment
based on the statute of frauds and; the court has not yet ruled on this separate motion. In June 2008, the Plaintiffs filed a Sixth Amended Petition conditionally adding claims for certain prospects
that had been previously settled by means of a Compromise and Settlement Agreement (the "Settlement Agreement"), entered in settlement of prior litigation among some of the parties, but only to the
extent that rescission of the prior Settlement Agreement was being sought by the Company. The Company is not seeking rescission of the prior Settlement Agreement and responded accordingly in its
Fourth Amended Original Counterclaim and Claims Against Additional Parties filed on October 16, 2008. On October 17, 2008, the plaintiffs filed their Seventh Amended Petition adding a
claim for breach of the Settlement Agreement. The trial, originally scheduled to begin September 10, 2007, has been reset several times, most recently for December 8, 2008, and will be
reset in 2009 by the newly-elected judge of the 215th Judicial District Court. In December 2008, one of the Blake counter-defendants filed a motion to arbitrate, which motion has not been heard
by the court. Extensive written

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15. COMMITMENTS AND CONTINGENCIES (Continued)

discovery
has occurred in the case, and the parties are engaging in fact and expert witness depositions. The Company has responded and will continue to respond aggressively to this lawsuit, and
believes it has meritorious defenses and counterclaims.

Diana Reyes, et al. v. Edge Petroleum Operating Company, Inc., et al.On January 8, 2008, the Company was served with a wrongful death
action filed in Hidalgo County, Texas. Plaintiffs allege negligence and gross negligence resulting from a fatality accident at the Slick State B-12 well site, on the Company's Bloomberg
Flores lease in Starr County, Texas. The plaintiffs are the widow and minor children of Mr. Reyes, who was killed in a one-car fatality accident on August 5, 2007.
Mr. Reyes was an employee of Payzone Logging, a vendor of the Company. In September 2008, the defendants in this case, including the Company, reached a settlement with the plaintiffs in the
amount of $175,000, all of which was paid by third party insurance. Neither the
Company nor its insurance carrier was required to contribute to the settlement pool. This matter was dismissed by the court on December 17, 2008.

Mary Jane Carol Trahan Champagne, et al. v. Edge Petroleum Exploration Company, et al.On September 19, 2008 the Company was sued in state
district court in Vermilion Parish, Louisiana by Mary Jane Trahan, Carol Trahan Champagne and 29 other plaintiffs alleging breach of obligations under mineral leases in Vermilion Parish regarding the
Trahan No. 1 well and the Trahan No. 3 well (MT RC SUB reservoir). Plaintiffs are seeking unspecified damages for lost revenue, lost royalties and devaluation of property interest
sustained as a result of the defendants' alleged negligent and improper drilling operations on the Trahan No. 1 well and the Trahan No. 3 well, including alleged failure to prevent
underground water from flooding and destroying plaintiffs' portion of the reservoir beneath plaintiffs' property. Plaintiffs also allege defendants failed to "block squeeze" sections of the Trahan
No. 3 well as would a prudent operator. This lawsuit, previously removed from the state court to the federal district court for the Western District of Louisiana, Lafayette Division, has been
remanded to state court. The Company's insurance carrier has retained counsel to represent the Company in this matter. The Company has not established a reserve with respect to this claim and it is
not possible to determine what, if any, its ultimate exposure might be in this matter. The Company intends to vigorously defend itself in this lawsuit.

John Lemke, et al. v. Edge Petroleum CorporationIn October 2008, the Company was sued by alleged assignees of Continental Seismic over an alleged
contract to receive a royalty of two-tenths of one percent in certain alleged areas developed for oil and gas in South Louisiana. The Company has filed an answer generally denying the
allegations and raising the defenses of the statute of limitations bar and laches. No discovery has been served. The court recently entered a docket control order which establishes a discovery
timetable and a trial date of November 30, 2009. The Company has not established a reserve with respect to this claim and has not determined what, if any, the Company's ultimate exposure might
be in this matter. The Company will respond aggressively to this lawsuit, and believes it has meritorious defenses.

16. SALES TO MAJOR CUSTOMERS AND OPERATORS

In accordance with SFAS No. 131,Disclosures about Segments of an Enterprise and Related Information, public business enterprises
are required to report financial and other information about operating segments of the entity. Operating segments are defined as components of an enterprise that engage in activities from which it may
earn revenues and incur expenses for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. SALES TO MAJOR CUSTOMERS AND OPERATORS (Continued)

the
purpose of allocating resources and assessing performance. Segment reporting is not applicable to the Company, as it has a single company-wide management team that administers all
properties as a whole rather than by discrete operating segments. The Company tracks only basic operational data by area and does not maintain complete separate financial statement information by
area. The Company measures financial performance as a single enterprise and not on an area-by-area basis. Throughout the year, the Company allocates capital resources on a
project-by-project basis, across the entire asset base to maximize profitability without regard to individual areas or segments.

SFAS
No. 131 also establishes standards for disclosures about major customers. The Company sold natural gas and crude oil production representing 10% or more of its total revenues
for the years ended December 31, 2008, 2007, and 2006 as listed below:

For the Year Ended
December 31,Purchaser

2008

2007

2006Integrys Energy Services, Inc.(1)


30
%

22
%

*Kinder Morgan


18
%

20
%

37
%Gulfmark Energy, Inc.


12
%

11
%

5
%Copano Field Services


6
%

5
%

10
%ChevronTexaco Inc.


4
%

4
%

12
%Kerr-McGee Oil & Gas


*


*


10
%






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

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. INCOME TAXES

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

For the years ended December 31,2008

2007

2006(in thousands)CurrentFederal

$


$


$
51State


(265
)

10


Total Current


(265
)

10


51DeferredFederal


(11,808
)

3,474


(21,959
)State


(3,705
)

249


333Total Deferred


(15,513
)

3,723


(21,626
)Income tax expense (benefit)

$
(15,778
)
$
3,733

$
(21,575
)


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

For the years ended December 31,2008

2007

2006(in thousands)Income (Loss) Before Income Taxes

$
(348,668
)
$
10,305

$
(62,836
)Statutory tax rate


35
%

35
%

35
%Tax expense (benefit) computed on statutory rate

$
(122,034
)
$
3,607

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


(3,970
)

(209
)

333Change in valuation allowance


110,207


468


Expenses not deductible for tax purposes and other


19


(133
)

85Total income tax expense (benefit)

$
(15,778
)
$
3,733

$
(21,575
)Effective tax rate


4.5
%

36.2
%

34.3
%


The
effect of share-based compensation expense for tax purposes in excess of or less than amounts recognized for financial accounting purposes was recorded directly to stockholders'
equity in the amounts of approximately $(0.2) million and $0.5 million for 2007 and 2006, respectively. For 2008, the effect of share-based compensation expense for tax purposes was less than
amounts recognized for financial accounting purposes and was recorded as a tax expense in the amount of approximately $0.6 million.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. INCOME TAXES (Continued)

Significant
components of the Company's deferred tax liabilities and assets as of December 31, 2008 and 2007 are as follows:

As of December 31,2008

2007(in thousands)Deferred tax liabilitycurrent:Price-risk management liability

$
(4,738
)
$
Deferred tax assetcurrent:Price-risk management asset





4,315Compensation cost


1,326


1,222Expenses not currently deductible for tax purposes





238Other


98


43Deferred tax assetcurrent


1,424


5,818Net deferred tax asset (liability)current

$
(3,314
)
$
5,818Deferred tax liabilitylong-term:Book basis of oil and natural gas properties in excess of tax basisFederal & State

$


$
(75,002
)Deferred tax assetlong-term:Book basis of oil and natural gas properties less than tax basisFederal & State


67,406


Net operating loss carryforwardFederal


43,714


51,262Net operating loss carryforwardStates


1,996


1,844Accretion on ARO


413


344Federal alternative minimum tax credits


267


497Other


193


197Deferred tax assetlong-term


113,989


54,144Net deferred tax asset (liability)long-term


113,989


(20,858
)Net deferred tax asset (liability), before valuation allowance


110,675


(15,040
)Valuation allowance


(110,675
)

(468
)Net deferred tax asset (liability)

$


$
(15,508
)


At
December 31, 2008, total deferred taxes included $43.7 million of federal and $2.0 million of state net operating loss ("NOL") carryforwards. In addition to the
deferred tax assets associated with NOLs, the Company has additional net deferred tax assets of approximately $65.0 million related to both federal and state tax positions. In recording
deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred
income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company considers the scheduled
reversal of deferred income tax liabilities and projected future taxable income for this determination. The Company believes that after considering all the available objective evidence, both positive
and negative, historical and prospective, with greater weight given to the historical evidence, and in light of the current market situation and the uncertainty

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. INCOME TAXES (Continued)

surrounding
the Company's Revolving Facility and related Amended Consent (see Note 11), management is not able to determine that it is more likely than not that the deferred tax assets will be
realized and therefore has established a full valuation allowance to reduce the net deferred tax asset to zero at December 31, 2008. The Company will continue to assess the valuation allowance
against deferred tax assets considering all available information obtained in future reporting periods. If the Company achieves profitable operations in the future, it may reverse a portion of the
valuation allowance in an amount at least sufficient to eliminate any tax provision in that period. The valuation allowance has no impact on the Company's NOL position for tax purposes, and if the
Company generates taxable income in future periods, it will be able to use its NOLs to offset taxes due at that time.

Tax
carryforwards at December 31, 2008, which are available for utilization on future income tax returns, are as follows:

Year of Expiration

Domestic

State(in thousands)2009

$


$
1222010





762011





7022012





2,9972013


631


702014





9202015





2,2632016





6,3032017





1982018


7,032


1,2192019


4,451


1,1772020


8,046


7602021


10,711


1,3812022


9,218


3,0072023


22,045


302024


3,276


642025


5,407


92026


6,869


402027


32,653


582028


14,557


24Net operating loss

$
124,896

$
21,420


The
Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. The Company's tax periods are open with the exception of Texas which is
audited through the 2007 report years. The Texas Comptroller's Office began an audit of the 2004 through 2007 report years during the latter part of 2007, completing the audit in 2008 with no
adjustment proposed.

Upon
adoption of FIN 48 on January 1, 2007, the Company recognized a liability of $534,035 which was a reduction in the January 1, 2007 retained earnings balance.
During 2008, the Company recorded an income tax benefit of approximately $0.4 million as a result of the conclusion of a state

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. INCOME TAXES (Continued)

audit
where no prior benefit was taken. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

(in thousands)Balance at January 1, 2008

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


Additions for tax positions of prior years


Reductions for tax positions of prior years


(432
)Settlements


Balance at December 31, 2008

$
102


The
amount recorded does not include interest as the anticipated adjustments more likely than not will result in no current tax due as a result of NOL carryovers. The unrecognized tax
benefits of approximately $0.1 million would impact the Company's effective tax rate if ultimately recognized. The Company does not expect the amount of unrecognized tax benefits to materially
change in 2009. The Company recognizes interest and penalties related to unrecognized tax benefits in tax expense. The Company recognized no interest or penalties during the year ended
December 31, 2008.

18. 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, 2008, 2007 and 2006, the Company contributed approximately $0.5 million,
$0.6 million, and $0.5 million, respectively, to the Plan.

19. EQUITY AND STOCK PLANS

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

Share-Based CompensationThe Company established the Incentive Plan of Edge Petroleum Corporation (the "Incentive Plan") in conjunction with its
initial public offering in March 1997. The Incentive Plan is discretionary and provides for the granting of awards, including options for the purchase of the Company's common stock and for the
issuance of restricted and/or unrestricted common stock to directors, officers, employees and independent contractors of the Company. The options and restricted stock granted to date vest over periods
of two to four years. The Company amended the Incentive Plan (i) in December 2003 to increase the shares available under the plan from 1.2 million shares to 1.7 million shares and
(ii) in June 2006 to increase the shares available under the Plan from 1.7 million shares to 2.2 million shares. Of the aggregate 2.2 million shares of common stock
reserved for grants under the Incentive Plan, 423,768 shares were available for future grants at

F-40

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. EQUITY AND STOCK PLANS (Continued)

December 31,
2008. The following nonqualified stock option awards and restricted stock unit grants were made under the Incentive Plan during each of the years indicated below:

Number
Granted

Market Value on
Date of GrantOptions Awards:2008




2007




2006




Restricted Stock Awards(1):2008


1,600

$6.122007


272,640

$5.92 to $17.592006


326,280

$16.42 to $32.40


---

As
a component of his employment agreement with the Company, John Elias, CEO and Chairman of the Board, has been granted option awards and a restricted stock award outside of the
Incentive Plan. Mr. Elias has also been granted options and restricted stock under the Incentive Plan. The options vest and become exercisable over a two year period subsequent to issue. The
restricted stock is issued over three to four years in accordance with the award's vesting schedule. Compensation expense is amortized over the vesting period and offset to additional paid in capital
("APIC"). The amortization of compensation expense related to this award is included in general and administrative expenses on the consolidated statement of operations. Below is a summary of options
and restricted stock grants made to Mr. Elias outside of the Incentive Plan:

Date Granted

Shares
Outstanding

Exercise
Price

Date ExercisableOptions(1):01/08/1999(2)


200,000

$
4.22

One-third upon issue and one-third upon each of January 1, 2000 and 200101/03/2000


50,000

$
3.16

100% January 200201/03/2001


50,000

$
8.88

100% January 200301/03/2002


50,000

$
5.18

100% January 200404/02/2002


24,000

$
5.59

100% April 200401/23/2003


50,000

$
3.88

100% January 200504/01/2004


37,000

$
13.99

100% January 2006Restricted Stock(3):04/02/2001


14,000




Ratably over three years beginning on the first anniversary of the date of grant


---

F-41

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. EQUITY AND STOCK PLANS (Continued)

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

Under
the modified prospective approach, SFAS No. 123(R) applies to new awards and to awards that were outstanding on January 1, 2006 that are subsequently modified,
repurchased or cancelled. Under the modified prospective approach, compensation cost recognized in the first quarter of fiscal 2006 includes compensation cost for all share-based payments granted
prior to, but not yet vested, as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of SFAS No. 123 and compensation
cost for all share-based payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123(R).
Prior periods were not restated to reflect the impact of adopting the new standard. Share-based compensation costs for the years ended December 31, 2008, 2007 and 2006 were:

Year Ended December 31,2008

2007

2006(in thousands)Stock options

$


$


$
69Restricted stock units


1,551


3,004


1,908Total share-based compensation

$
1,551

$
3,004

$
1,977


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

F-42

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. EQUITY AND STOCK PLANS (Continued)

Stock Options

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



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

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

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

F-43

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. EQUITY AND STOCK PLANS (Continued)

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

Number of
Shares

Weighted
Average
Exercise
Price

Weighted
Average
Remaining
Contract Life

Aggregate
Intrinsic ValueFor the Year Ended December 31, 2006:Outstanding, beginning of period


735,450

$
5.93Exercised


(84,750
)

6.80Outstanding, end of period


650,700


5.82

3.92 years

$
8,200,945Exercisable, end of period


650,700

$
5.82

3.92 years

$
8,200,945For the Year Ended December 31, 2007:Outstanding, beginning of period


650,700

$
5.82Exercised


(7,000
)

6.01Forfeited


(100
)

13.50Outstanding, end of period


643,600


5.82

2.88 years

$
699,370Exercisable, end of period


643,600

$
5.82

2.88 years

$
699,370For the Year Ended December 31, 2008:Outstanding, beginning of period


643,600

$
5.82Exercised





Forfeited





Outstanding, end of period


643,600


5.82

1.88 years

$
Exercisable, end of period


643,600

$
5.82

1.88 years

$



The
Company determines the fair value of options at the date of grant using the Black-Scholes option pricing model. There were no options granted for the years ended December 31,
2008, 2007 and 2006. There were 100 options forfeited for the year ended December 31, 2007 and none for the years ended December 31, 2006 and 2008.

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

F-44

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. EQUITY AND STOCK PLANS (Continued)

A
summary of additional information related to options outstanding as of December 31, 2008 follows:

All Options

Options ExercisableRange of
Exercise Price

Options
Outstanding

Weighted
Average
Remaining
Contractual Life
(in years)

Weighted
Average
Exercise
Price

Number
Exercisable

Weighted
Average
Exercise
Price$3.00 - $3.88


119,500


2.51

$
3.52


119,500

$
3.52$4.22


200,000
(1)



$
4.22


200,000

$
4.22$5.18 - $5.73


155,500


3.28

$
5.45


155,500

$
5.45$7.06 - $7.58


68,600


0.55

$
7.13


68,600

$
7.13$8.88


50,000


2.00

$
8.88


50,000

$
8.88$13.99


50,000


5.25

$
13.99


50,000

$
13.99


---

Restricted Stock

In addition to stock options, the Company issues restricted stock and restricted stock units. For awards issued to date, shares of
common stock associated with the restricted stock awards will be issued, subject to continued employment, ratably over three or four years in accordance with the award's vesting schedule, beginning on
the first or second anniversary of the date of grant. Compensation expense from restricted stock and restricted stock units is amortized over the vesting period and offset to APIC. The share-based
expense for these awards was determined based on the market price of the Company's stock at the date of grant applied to the total number of shares that were anticipated to fully vest and then
amortized over the vesting period. As of December 31, 2008, the Company had unamortized share-based compensation of $2.3 million associated with these awards. The cost is expected to be
recognized over a weighted-average period of approximately two years. The total fair value of shares vested during the year ended December 31, 2008 was $0.3 million. Upon adoption of
SFAS No. 123(R), the Company recorded an immaterial cumulative effect of change in accounting principle as a result of the change in policy from recognizing forfeitures as they occur to
recognizing expense based on the Company's expectation of the awards that will vest over the requisite service period for its restricted stock and restricted stock unit awards. This amount was
recorded as compensation cost in general and administrative expenses in the consolidated statement of operations.

F-45

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. EQUITY AND STOCK PLANS (Continued)

A summary of the status of the unvested shares of restricted stock and changes during 2008, 2007 and 2006 is presented below:

Number of
Unvested
Restricted
Shares

Weighted
Average
Grant-Date
Fair ValueUnvested shares as of January 1, 2008


584,782

$
15.78Granted


1,600

$
6.12Vested


(97,971
)
$
18.86Forfeited


(183,391
)
$
14.90Unvested shares as of December 31, 2008


305,020

$
15.28Unvested shares as of January 1, 2007


436,624

$
18.43Granted


293,770

$
13.12Vested


(105,063
)
$
19.23Forfeited


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


584,782

$
15.78Unvested shares as of January 1, 2006


218,954

$
14.90Granted


333,600

$
19.32Vested


(98,720
)
$
13.14Forfeited


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


436,624

$
18.43


The
aggregate intrinsic value of restricted stock vested during 2008 was approximately $0.8 million.

Computation of Earnings per ShareThe Company accounts for earnings per share in accordance with SFAS No. 128, which establishes the
requirements for presenting earnings per share ("EPS"). SFAS No. 128 requires the presentation of "basic" and "diluted" EPS on the face of the statement of operations. Basic EPS amounts are
calculated using the weighted average number of common shares outstanding during each period. Diluted EPS assumes the exercise of all stock options, warrants and convertible securities having exercise
prices less than the average market price of the common stock during the periods, using the treasury stock method. When a loss from continuing operations exists, as in the periods presented, potential
common shares are excluded in the computation of diluted EPS because their inclusion would result in an anti-dilutive effect on per share amounts.

Diluted
EPS also includes the effect of convertible securities by application of the "if-converted" method. Under this method, if an entity has convertible preferred stock
outstanding, the preferred dividends applicable to the convertible preferred stock are added back to the numerator. The convertible preferred stock is assumed to have been converted at the beginning
of the period (or at time of issuance, if later) and the resulting common shares are included in the denominator of the EPS calculation. In applying the if-converted method, conversion is
not assumed for purposes of computing diluted EPS if the effect would be anti-dilutive. During 2008 and 2007, conversion of the 5.75%

F-46

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19. EQUITY AND STOCK PLANS (Continued)

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

Year Ended December 31,2008

2007

2006Income
(Loss)

Shares(1)

Per Share
Amount

Income
(Loss)

Shares(2)

Per Share
Amount

Income
(Loss)

Shares(3)

Per Share
Amount(in thousands, except per share amounts)Net income (loss)

$
(332,890
)






$
6,572







$
(41,261
)Less: Preferred stock dividends paid


(6,544
)







(7,577
)







Less: Preferred stock dividends in arrears


(1,722
)
















Basic EPSNet loss to common stockholders


(341,156
)

28,682

$
(11.89
)

(1,005
)

27,613

$
(0.04
)

(41,261
)

17,368

$
(2.38
)Effect of dilutive securities:Restricted stock units


























Common stock options


























Convertible preferred stock


























Diluted EPSNet loss to common stockholders plus assumed conversions

$
(341,156
)

28,682

$
(11.89
)
$
(1,005
)

27,613

$
(0.04
)
$
(41,261
)

17,368

$
(2.38
)


---

Associated with the exercise of stock options and vesting of restricted stock units, the Company received a tax benefit of approximately
$0.5 million in 2006. During 2007, the Company recorded charges associated with the exercise of stock options and vesting of restricted stock units of approximately $0.2 million. The tax
benefit or charge is recorded as an increase or decrease in APIC.

20. RELATED PARTY TRANSACTIONS

The transactions described below were with affiliates, and it is possible that the Company would have
obtained different terms from a truly unaffiliated third-party. In addition, see Note 15 regarding certain disputes with entities involving Mr. Sfondrini (a director of the Company).

Affiliates' Ownership in ProspectsEdge Group Partnership, a Connecticut general partnership composed of the three Connecticut limited partnerships
(Edge I Limited Partnership, The Edge II Limited Partnership, and The Edge III Limited Partnership) whose general partners are Mr. Sfondrini

F-47

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. RELATED PARTY TRANSACTIONS (Continued)

and
a corporation wholly owned by him; Edge Holding Company, L.P., a limited partnership of which Mr. Sfondrini and a corporation wholly owned by him are the general partners; Edge
Option I Limited Partnership, Edge Option II Limited Partnership and Edge Option III Limited Partnership, limited partnerships whose general partners are Mr. Sfondrini and a corporation
controlled by him; Andex Energy Corporation and Texedge Energy Corporation, corporations of which Mr. Andrews (a director of the Company) is an officer and members of his immediate family hold
ownership interests; Mr. Raphael (a former director of the Company) and Essex II Joint Venture, own certain working interests in the Company's Nita and Austin Prospects and certain other wells
and prospects operated by the Company. These working interests aggregate 7.19% in the Austin Prospect, 6.27% in the Nita Prospect and are negligible in other wells and prospects. These working
interests bear their share of lease operating costs and royalty burdens on the same basis as the Company. In addition, Bamaedge, L.P., a limited partnership of which Andex Energy Corporation is
the general partner, and Mr. Raphael also hold overriding royalty interests with respect to the Company's working interest in certain wells and prospects. Neither Mr. Raphael nor
Bamaedge L.P. has an overriding interest in excess of 0.075% in any one well or prospect. Essex I Joint Venture and Essex II Joint Venture (a joint venture of which Mr. Sfondrini and a
company wholly owned by him are the managers) own royalty and overriding royalty interests in various wells operated by the Company. The combined royalty and overriding royalty interests of the Essex
I and Essex II Joint Ventures do not exceed 6.2% in any one well or prospect. In September 2006, the Essex I and Essex II Joint Ventures sold all of their interests in wells operated by the Company
except for one well in which Essex II has a 1% gross working interest. Mr. Tugwell (an officer of the Company) and Mr. Gabrisch (a former vice president of the Company) own overriding
royalty interests in various wells as a result of awards they received prior to 2000 when the Company had an overriding royalty program in effect for certain key employees. The gross amounts paid or
accrued to these persons and entities by the Company in 2008 (including net revenue, royalty and overriding royalty interests) and the amounts these same persons and entities paid

F-48

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. RELATED PARTY TRANSACTIONS (Continued)

to
the Company for their respective share of lease operating expenses and other costs are set forth in the following table:

Total Amounts Paid by the Company to Owners Including Overriding Royalty(1)Owner

2008

2007

2006Andex Corporation /Texedge Corporation

$
1,675

$
10,343

$
4,375Bamaedge, L.P.


1,725


1,551


1,447Edge Group Partnership


58,881


683,996


428,321Edge Holding Co., L.P.(2)


28,664


179,084


76,169Edge Limited Partnership(2)


1,178


2,139


9,472Edge Limited Partnership II


1,767


3,209


14,208Edge Option I


98


178


789Edge Option II


98


178


789Edge Option III


403


732


3,240Essex I Royalty Joint Venture


47


13,366


18,641Essex II Royalty Joint Venture


25,921


193,181


112,912Mark J. Gabrisch(3)


*


*


1,061John O. Tugwell


77


279


760Stanley Raphael(4)





8,991


4,268Total

$
120,534

$
1,097,227

$
676,452


---

F-49

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. RELATED PARTY TRANSACTIONS (Continued)

Lease Operating Expenses Paid to the Company by OwnersOwner

2008

2007

2006Andex Corporation /Texedge Corporation

$
306

$
2,417

$
Bamaedge, L.P.


130


151


318Edge Group Partnership


40,961


683,996


308,516Edge Holding Co., L.P.(1)


16,175


137,593


54,422Edge Limited Partnership I(1)





1,771


5,628Edge Limited Partnership II





2,656


8,441Edge Option I





148


518Edge Option II





148


518Edge Option III





605


2,345Essex II Royalty Joint Venture


11,715


156,995


64,248Stanley Raphael(2)





6,261


2,595Total

$
69,287

$
992,741

$
447,549


---

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

A summary of non-cash investing and financing activities for the years ended December 31, 2008, 2007 and 2006 is presented below:

Description

Number
of shares
issued

Fair Market
Value(in thousands)2008:Shares issued to satisfy restricted stock grants


86

$
1,642Shares issued to fund the Company's matching contribution under the Company's 401(k) plan


204

$
5952007:Shares issued to satisfy restricted stock grants


133

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


37

$
5082006:Shares issued to satisfy restricted stock grants


119

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


22

$
429


F-50

---



Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

For
the years ended December 31, 2008, 2007 and 2006, the non-cash portion of Asset Retirement Costs was $0.5 million, $3.0 million, and
$0.4 million, respectively. A supplemental disclosure of cash flow information for the years ended December 31, 2008, 2007 and 2006 is presented below:

For the Year Ended December 31,2008

2007

2006(in thousands)Cash paid during the period for:Interest, net of amounts capitalized

$
12,225

$
10,123

$
1,959Current state income tax





5


Federal tax deposit


220





94




22. 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(1)

Third
Quarter(1)

Second
Quarter

First
Quarter(in thousands, except per share amounts)2008(1):Oil and natural gas revenue

$
42,017

$
106,641

$
(7,538
)
$
17,657Operating expenses


(258,077
)

(164,467
)

(33,912
)

(38,088
)Operating loss


(216,060
)

(57,826
)

(41,450
)

(20,431
)Other expense, net


(3,118
)

(2,898
)

(2,491
)

(4,394
)Income tax (expense) benefit


(29,700
)

20,714


16,118


8,646Net income (loss)

$
(248,878
)
$
(40,010
)
$
(27,823
)
$
(16,179
)Basic earnings (loss) per share

$
(8.71
)
$
(1.47
)
$
(1.04
)
$
(0.64
)Diluted earnings (loss) per share

$
(8.71
)
$
(1.47
)
$
(1.04
)
$
(0.64
)2007(2):Oil and natural gas revenue

$
35,931

$
48,184

$
53,902

$
22,883Operating expenses


(39,884
)

(36,364
)

(34,532
)

(28,628
)Operating income (loss)


(3,953
)

11,820


19,370


(5,745
)Other expense, net


(2,846
)

(2,334
)

(3,049
)

(2,958
)Income tax (expense) benefit


2,496


(3,460
)

(5,704
)

2,935Net income (loss)

$
(4,303
)
$
6,026

$
10,617

$
(5,768
)Basic earnings (loss) per share

$
(0.22
)
$
0.14

$
0.30

$
(0.29
)Diluted earnings (loss) per share

$
(0.22
)
$
0.14

$
0.28

$
(0.29
)


---

F-51

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

23. 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 and impairments relating to the Company's oil and natural gas producing activities,
all
of which are conducted within the continental United States, are summarized below:

As of December 31,2008

2007(in thousands)Developed oil and natural gas properties(1)

$
1,118,774

$
1,059,788Unevaluated oil and natural gas properties


16,432


34,865Accumulated depletion and impairments


(831,763
)

(381,689
)Net capitalized cost

$
303,443

$
712,964


---

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

For the Year Ended December 31,2008

2007

2006(in thousands)Acquisition cost:Unproved properties

$
12,752

$
64,483

$
21,661Proved properties





336,022


36,573Exploration costs


5,663


41,240


17,898Development costs(1)


41,340


74,920


65,140Total costs incurred

$
59,755

$
516,665

$
141,272


---

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.

F-52

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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

For the Year Ended December 31,2008

2007

2006(in thousands)Oil and natural gas revenue

$
158,777

$
160,900

$
129,744Less operating expenses:Oil and natural gas operating expenses and ad valorem taxes


17,576


21,774


11,836Production taxes


9,000


8,422


6,421Accretion expense


379


297


189Depletion expense


87,223


90,826


60,472Impairment of oil and natural gas properties


362,851





96,942Income tax expense (benefit)(1)


(111,388
)

13,853


(16,141
)Results of operations from oil and gas producing activities

$
(206,864
)
$
25,728

$
(29,975
)


---

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

The
Company's reserves decreased in 2008 due to lower commodity prices, production, property sales and revisions to previous estimates. The Company was unable to replace the production
the Company generated due to its reduced capital spending program and higher drilling and operating costs. However, the decrease was partially offset by extensions and discoveries that resulted from
the drilling of 25 gross (8.74 net) apparent successess recompletion of one well, and the addition of one proved undeveloped ("PUD") location. Revisions to previous estimates during 2008 were
primarily due to (1) commodity pricing that was significantly lower than year-end 2007, causing a number of PUD locations to be uneconomic and shortening the economic life of many
other properties, (2) results of actual drilling and recompletion operations and updated technical analysis, (3) updates to shrink and differential factors and (4) updated
performance (both positive and negative) on existing producing wells. The Company's net ownership in estimated quantities of proved oil and natural gas reserves and

F-53

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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

Natural
Gas
(MMcf)

Oil &
Condensate
(MBbls)

Natural
Gas
Liquids
(MBbls)

Total
(MMcfe)Proved developed and undeveloped reservesJanuary 1, 2006


82,290


2,176


1,234


102,750Revisions of previous estimates


(13,526
)

(158
)

833


(9,476
)Purchase of oil and gas properties


12,083


307


15


14,015Extensions and discoveries


9,202


431


71


12,214Sales of natural gas properties


(52
)

(12
)

(5
)

(154
)Production


(13,850
)

(345
)

(222
)

(17,251
)December 31, 2006


76,147


2,399


1,926


102,098Proved developed reserves at year end 2006


60,163


1,977


1,181


79,111January 1, 2007


76,147


2,399


1,926


102,098Revisions of previous estimates


(65,450
)

(769
)

(11
)

(70,134
)Purchase of oil and gas properties


98,491


1,468


2,392


121,651Extensions and discoveries


26,306


468


1,111


35,780Sales of natural gas properties


(1,397
)

(62
)

(6
)

(1,805
)Production


(17,536
)

(460
)

(637
)

(24,118
)December 31, 2007


116,561


3,044


4,775


163,472Proved developed reserves at year end 2007


88,134


2,580


3,732


126,005January 1, 2008


116,561


3,044


4,775


163,472Revisions of previous estimates


(18,643
)

(312
)

(961
)

(26,280
)Purchase of oil and gas properties











Extensions and discoveries


7,034


159


303


9,806Sales of natural gas properties


(3,272
)

(324
)

(79
)

(5,690
)Production


(12,059
)

(294
)

(559
)

(17,176
)December 31, 2008


89,621


2,273


3,479


124,132Proved developed reserves at year end 2008


68,955


1,971


2,833


97,783


F-54

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Standardized MeasureThe Standardized Measure of Discounted Future Net Cash Flows relating to the Company's ownership interests in proved oil and
natural gas reserves for each of the three years ended December 31, 2008 is shown below:

For the Year Ended December 31,2008(1)

2007

2006(in thousands)Future cash inflows

$
713,025

$
1,314,304

$
616,605Future oil and natural gas operating expenses


(180,828
)

(253,071
)

(131,926
)Future development costs


(119,206
)

(155,991
)

(75,389
)Future income tax expense





(114,311
)

(65,738
)Future net cash flows


412,991


790,931


343,55210% discount factor


(135,786
)

(248,412
)

(110,346
)Standardized measure of discounted future net cash flows

$
277,205

$
542,519

$
233,206


---

In
accordance with SEC regulations, the oil and natural gas prices in effect at December 31, 2008, 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 as follows:

Year Ended December 31,2008

2007

2006Natural gas ($ per MMBtu)

$
5.71

$
6.80

$
5.62Natural gas liquids ($ per Bbl)


26.76


57.60


36.64Oil and condensate ($ per Bbl)


44.60


96.00


61.06


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

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

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

F-55

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Table of Contents

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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

For the Year Ended December 31,2008

2007

2006(in thousands)Changes due to current year operations:Sales of oil and natural gas, net of oil and natural gas operating expenses

$
(133,673
)
$
(144,225
)
$
(101,520
)Sales of oil and natural gas properties


(21,413
)

(3,621
)

(618
)Purchase of oil and gas properties





257,789


34,855Extensions and discoveries


60,690


120,691


42,085Changes due to revisions of standardized variables:Prices and operating expenses


(224,854
)

577,668


(190,802
)Revisions of previous quantity estimates


(74,606
)

(621,745
)

(29,018
)Estimated future development costs


35,321


60,578


44,992Income taxes


67,380


(29,070
)

72,792Accretion of discount


54,252


23,320


34,379Production rates (timing) and other


(28,411
)

67,928


(17,729
)Net change


(265,314
)

309,313


(110,584
)Beginning of year


542,519


233,206


343,790End of year

$
277,205

$
542,519

$
233,206


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-56

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Table of Contents

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 Appendix A to the Joint Proxy Statement/Prospectus contained in the Company's Registration Statement on Form S-4/A
filed on January 15, 1997 (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.2.7



Agreement and Plan of Merger, dated July 14, 2008, among Chaparral Energy, Inc., Chaparral Exploration, L.L.C. and Edge Petroleum Corporation (Incorporated by reference from exhibit 2.1 to the
Company's Current Report on Form 8-K filed July 15, 2008). Pursuant to Item 601(b)(2) of Regulation S-K, the Company had omitted the disclosure schedules to the Merger Agreement from this Exhibit 2.1. 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).


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Table of Contents

Exhibit No.3.4



Bylaws of the Company (Incorporated by reference from exhibit 3.3 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999 (File No. 000-22149)).3.5



First Amendment to Bylaws of the Company on September 28, 1999 (Incorporated by reference from exhibit 3.2 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30,
 1999 (File No. 000-22149)).3.6



Second Amendment to Bylaws of the Company on May 7, 2003 (Incorporated by reference from exhibit 3.4 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended March 31,
2003).3.7



Certificate of Designations establishing the 5.75% Series A cumulative convertible perpetual preferred stock, dated January 25, 2007 (Incorporated by reference to exhibit 3.1 to the Company's Current
Report on Form 8-K filed January 30, 2007).3.8



Third Amendment to Bylaws of Edge Petroleum Corporation on October 21, 2008 (Incorporated by reference to exhibit 3.4 to the Company's Current Report on Form 8-K filed October 23,
2008).4.1



Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference from exhibit 10.1(a) to Miller's Annual Report on Form 10-K for the year ended December 31, 1997
(File No. 000-23431)).4.2



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's Registration Statement on Form S-8 filed on
April 11, 2001 (Registration No. 333-58678)).4.3



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's Registration Statement on Form S-8 filed on
April 11, 2001 (Registration No. 333-58678)).4.4



Form of Miller Stock Option Agreement (Incorporated by reference from exhibit 10.1(b) to Miller's Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 000-23431)).4.5



Fourth Amended and Restated Credit Agreement dated January 31, 2007 by and among Edge Petroleum Corporation, as borrower, and Union Bank of California, N.A., as Administrative Agent and Issuing Lender, and
the other lenders party thereto (Incorporated by reference from exhibit 4.1 to the Company's Current Report on Form 8-K filed on February 5, 2007).4.6



Amendments No. 1, 2 and 3 to the Fourth Amended and Restated Credit Agreement dated as of July 11, 2007, December 10, 2007 and May 8, 2008, respectively, by and among Edge Petroleum Corporation, as
borrower, and Union Bank of California, N.A., as Administrative Agent and Issuing Lender, and the other lenders party thereto (Incorporated by reference from exhibit 4.9 to the Company's Quarterly Report on Form 10-Q for the quarterly
period ending March 31, 2008 filed on May 12, 2008).4.7



Consent, executed July 11, 2008, among Edge Petroleum Corporation, the Lenders party thereto and Union Bank of California, N.A., as administrative agent for such Lenders (Incorporated by reference from
exhibit 4.1 to the Company's Current Report on Form 8-K filed July 15, 2008).4.8



Letter Agreement dated November 5, 2008 by and among Edge Petroleum Corporation, Union Bank of California, N.A., as Administrative Agent and Issuing Lender, and the other lenders party thereto (Incorporated
by reference from exhibit 4.11 to the Company's Quarterly Report on Form 10-Q for the quarterly period ending September 30, 2008 filed November 10, 2008).


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Table of Contents

Exhibit No.4.9



Consent and Agreement, executed February 9, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders. (Incorporated by reference
from exhibit 4.1 to the Company's Current Report on Form 8-K filed February 9, 2009).4.10



Consent and Agreement, executed March 10, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders. (Incorporated by reference
from exhibit 4.1 to the Company's Current Report on Form 8-K filed March 10, 2009).4.11



Consent and Agreement No. 4 executed March 16, 2009, among Edge Petroleum Corporation, the lenders party thereto and Union Bank of California, N.A., as administrative agent for such lenders. (Incorporated by
reference from exhibit 4.1 to the Company's Current Report on Form 8-K filed March 16, 2009).10.1



Form of Indemnification Agreement between the Company and each of its directors (Incorporated by reference from exhibit 10.7 to the Company's Registration Statement on Form S-4 (Registration
No. 333-17269)).10.2



Stock Option Plan of Edge Petroleum Corporation, a Texas corporation (Incorporated by reference from exhibit 10.13 to the Company's Registration Statement on Form S-4 (Registration No. 333-17269)).10.3



Employment Agreement dated as of November 16, 1998, by and between the Company and John W. Elias (Incorporated by reference from exhibit 10.12 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1998 (File No. 000-22149)).10.4



Amended and Restated Incentive Plan of Edge Petroleum Corporation as Amended and Restated Effective as of August 1, 2006 (Incorporated by reference from exhibit 10.4 to the Company's Quarterly Report on
Form 10-Q for the quarterly period ending June 30, 2006).10.5



Edge Petroleum Corporation Incentive Plan "Standard Non-Qualified Stock Option Agreement" by and between Edge Petroleum Corporation and the Officers named therein (Incorporated by reference from exhibit 10.2 to
the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999 (File No. 000-22149)).10.6



Edge Petroleum Corporation Incentive Plan "Director Non-Qualified Stock Option Agreement" by and between Edge Petroleum Corporation and the Directors named therein (Incorporated by reference from exhibit 10.3 to
the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999 (File No. 000-22149)).10.7



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).10.8



Form of Employee Restricted Stock Award Agreement under the Incentive Plan of Edge Petroleum Corporation (Incorporated by reference from exhibit 10.15 to the Company's Quarterly Report on Form 10-Q/A for the
quarterly period ended March 31, 1999 (File No. 000-22149)).10.9



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)).10.10



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)).*10.11



Summary of Compensation of Non-Employee Directors.


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Table of Contents

Exhibit No.*10.12



Salaries and Certain Other Compensation of Executive Officers.10.13



Description of Annual Cash Bonus Program for Executive Officers (Incorporated by reference from exhibit 10.2 to the Company's Current Report on Form 8-K filed March 12, 2007).10.14



New Base Salaries and Long-Term Incentive Awards for Certain Executive Officers (Incorporated by reference from exhibit 10.1 to the Company's Current Report on Form 8-K filed August 29,
2006).10.15



Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated November 16, 2006 (Incorporated by reference to exhibit 10.1 to the
Company's Current Report on Form 8-K filed January 16, 2007).10.16



Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated November 16, 2006 (Incorporated by reference to exhibit 10.2 to the
Company's Current Report on Form 8-K filed January 16, 2007).10.17



First Amendment of Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated December 16, 2006 (Incorporated by reference to
exhibit 10.3 to the Company's Current Report on Form 8-K filed January 16, 2007).10.18



Second Amendment of Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated January 15, 2007 (Incorporated by reference to
exhibit 10.1 to the Company's Current Report on Form 8-K filed January 19, 2007).10.19



First Amendment of Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated January 15, 2007 (Incorporated by reference to
exhibit 10.2 to the Company's Current Report on Form 8-K filed January 19, 2007).10.20



Third Amendment of Purchase and Sale Agreement between Smith Production, Inc., as seller, and Edge Petroleum Exploration Company, as purchaser, dated January 31, 2007 (Incorporated by reference to
exhibit 10.6 to the Company's Current Report on Form 8-K filed February 5, 2007).10.21



New Base Salaries of Executive Officers (Incorporated by reference from Exhibit 10.1 to the Company's Current Report on Form 8-K filed March 12, 2007).10.22



Form of Amended and Restated Severance Agreement dated April 3, 2008, between the Company and Executive Officers of the Company Named Therein (Incorporated by reference from exhibit 10.1 to the Company's
Current Report on Form 8-K filed April 4, 2008).10.23



Amended and Restated Severance Agreement dated April 3, 2008, between the Company and John W. Elias (Incorporated by reference from exhibit 10.2 to the Company's Current Report on Form 8-K filed
April 4, 2008).10.24



Amended and Restated Employment Agreement dated April 3, 2008, between the Company and John W. Elias (Incorporated by reference from exhibit 10.3 to the Company's Current Report on Form 8-K filed
April 4, 2008).10.25



First Amendment to Amended and Restated Severance Agreement, dated July 14, 2008, between the Company and John W. Elias (Incorporated by reference from exhibit 10.1 to the Company's Current Report on
Form 8-K filed July 15, 2008).


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Table of Contents

Exhibit No.10.26



First Amendment to Amended and Restated Severance Agreement, dated July 14, 2008, between the Company and Executive Officers of the Company Named Therein (Incorporated by reference from exhibit 10.2 to the
Company's Current Report on Form 8-K filed July 15, 2008).10.27



Merger Termination Agreement, dated December 16, 2008, among Chaparral Energy, Inc., Chaparral Exploration, L.L.C. and Edge Petroleum Corporation (Incorporated by reference to exhibit 10.1 to the
Company's Current Report on Form 8-K filed December 17, 2008).10.28



Termination and Settlement Agreement, dated December 16, 2008, among Magnetar Financial LLC, Investment Partners II (B), LLC, QRA SR, LLC, Triangle Peak Partners Private Equity, LP, Post Oak
Energy Capital, LP, Chaparral Energy, Inc., Chaparral Exploration, L.L.C. and Edge Petroleum Corporation (Incorporated by reference to exhibit 10.2 to the Company's Current Report on Form 8-K filed December 17,
2008).*12.1



Statement of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.*21.1



Subsidiaries of the Company.*23.1



Consent of BDO Seidman, LLP.*23.2



Consent of Ryder Scott Company.*23.3



Consent of W. D. Von Gonten & Co.*31.1



Certification by John W. Elias, Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*31.2



Certification by Gary L. Pittman, 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 Section 906 of the Sarbanes-Oxley Act of 2002.*32.2



Certification by Gary L. Pittman, Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*99.1



Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31, 2008.*99.2



Summary of Reserve Report of W. D. Von Gonten & Co. Petroleum Engineers as of December 31, 2008.


---

---