The following discussion and analysis should be read in conjunction with the "Management's Discussion and Analysis of Financial Condition and Results of Operations" section and audited consolidated financial statements and related notes thereto included in our Annual Report on Form 10-K and with the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report on Form 10-Q.

Disclosure Regarding Forward-Looking Statements

This report includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of historical facts included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, general economic, market or business conditions; the opportunities (or lack thereof) that may be presented to and pursued by us; competitive actions by other oil and natural gas companies; changes in laws or regulations; hurricanes and other natural disasters and other factors, including those listed in the "Risk Factors" section of our most recent Annual Report on Form 10-K, many of which are beyond our control. Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements, and we cannot assure you that the actual results or developments anticipated by us will be realized or, even if realized, that they will have the expected consequences to or effects on us, our business or operations. We have no intention, and disclaim any obligation, to update or revise any forward-looking statements, whether as a result of new information, future results or otherwise.

Overview

We are an independent oil and natural gas exploration and production company with our principal producing properties located along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, and in West Texas in the Permian Basin. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs.

Third Quarter 2009 Operational Highlights

• Oil and natural gas revenues decreased 40% to $22.2 million for the three months ended September 30, 2009 from $36.9 million for the three months ended September 30, 2008.

• Net income decreased 53% to $6.7 million for the three months ended September 30, 2009 from $14.1million for the three months ended September 30, 2008.

• Production increased 4% to 416,000 barrels of oil equivalent, or BOE, for the three months ended September 30, 2009 from 400,000 BOE for the three months ended September 30, 2008.

• During the three months ended September 30, 2009, we drilled ten wells and recompleted 18 wells.

• We sold 5,721 net acres in the Bakken for $5.8 million with an effective date of July 1, 2009.

2009 Production and Drilling Activity

During the three months ended September 30, 2009, our total net production was 373,000 barrels of oil, 161,000 thousand cubic feet of gas, or Mcf, and 651,000 gallons of liquids, for a total 416,000 BOE, compared to 361,000 barrels of oil, 135,000 Mcf of gas, and 695,000 gallons of liquids, or 400,000 BOE, for the three months ended September 30, 2008. Our total net production averaged approximately 4,519 BOE per day during the three months ended September 30, 2009 as compared to 4,352 BOE per day during the same period in 2008. The 4% percent increase in production is primarily related to the June 1, 2009 commencement of drilling activities in our WCBB field partially reduced by the sale of production in the Bakken.

WCBB. From January 1, 2009 through November 1, 2009, we recompleted 43 wells and drilled 11 WCBB wells with ten of the 11 completed as producers. We intend to recomplete a total of approximately 50 existing wells during 2009.

Aggregate net production from the WCBB field during the three months ended September 30, 2009 was 322,700 BOE, or 3,507 BOE per day, 95% of which was from oil. During October 2009, our average daily net production at WCBB was approximately 3,544 BOE, 97% of which was from oil and 3% which was from natural gas. The increase in October production is primarily due to the completion of two WCBB wells during late September and October 2009.

East Hackberry Field. From January 1, 2009 through November 1, 2009, we recompleted five existing wells and drilled two wells, one of which is awaiting completion. Currently, we are drilling our third well and intend to drill two or three additional wells during 2009. We entered into a two year exploration agreement with an active gulf coast operator covering approximately 3,058 net acres adjacent to our field. We are the designated operator under the agreement and will participate in proposed wells with at least a 70% working interest. We have licensed approximately 54 square miles of 3-D seismic data covering a portion of the area and are reprocessing the data.

Aggregate net production from the East Hackberry field during the three months ended September 30, 2009 was approximately 27,600 BOE, or 301 BOE per day, 96% of which was from oil and 4% of which was from natural gas. During October 2009, our average daily net production at East Hackberry was approximately 572 BOE, 94% of which was from oil and 6% of which was from natural gas. The increase in October 2009 production is due to the completion of a new well during October 2009 and resumed production from two of our producing wells required to shut in for drilling activities in the field.

West Hackberry Field. Aggregate net production from the West Hackberry field during the three months ended September 30, 2009 was approximately 4,300 BOE, or 47 BOE per day. During October 2009, our average daily net production at West Hackberry was approximately 51 BOE, 100% of which was from oil.

West Texas. On December 20, 2007, we completed the acquisition of 4,100 net acres and 32 producing wells in West Texas in the Permian Basin for approximately $83.8 million, with an effective date of November 1, 2007. In 2008, 31 gross (15.5 net) wells were drilled on this acreage, including one gross well spud in 2007 and completed in 2008 and one Henry Petroleum operated well. Subsequently, we have acquired an additional 4,095 net acres, bringing our total acreage position to 8,405 net acres. We recently drilled one gross well and anticipate drilling three to four more gross wells during 2009. In addition, we have recompleted two gross wells and intend to recomplete an additional two gross wells on this acreage during 2009.

Aggregate net production from the Permian field during the three months ended September 30, 2009 was approximately 51,600 BOE, or 561 BOE per day. During October 2009, average daily net production at Permian was approximately 567 BOE, of which approximately 54% was oil, 28% was natural gas liquids and 18% was natural gas.

Bakken. During May 2009, we sold approximately 12,270 net acres and approximately 190 net BOEPD of production for approximately $13.0 million, with an effective date of April 1, 2009. During September 2009, we sold approximately 5,721 net acres for $5.8 million with an effective date of July 1, 2009. As of November 1, 2009, we hold approximately 900 net acres, interests in four wells and an overriding royalty interest in certain wells that might be drilled in the future.

Aggregate net production from the Bakken play during the three months ended September 30, 2009 was approximately 9,300 BOE, or 101 BOE per day. During October 2009, average daily net production in Bakken was approximately 91 BOE. This decrease in production was primarily the result of normal production declines.

Grizzly. During the third quarter of 2006, we, through our wholly owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in Grizzly Oil Sands ULC, or Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford Capital LP, or Wexford. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 527,000 acres under lease and our net investment in Grizzly was $24.5 million at September 30, 2009. In addition, we have loaned Grizzly $14.5 million including interest and net of foreign currency adjustments as of September 30, 2009. During the 2006/2007, 2007/2008 and 2008/2009 winter delineation drilling seasons, Grizzly drilled an aggregate of 131 core holes and one water supply test well, tested five separate lease blocks and conducted a seismic program.

Thailand. During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex, at a cost of $2.4 million. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering three million acres which includes the Phu Horm Field. During the nine months ended September 30, 2009, we received $317,000 in distributions and paid $320,000 in cash calls, bringing our total net investment in Tatex (including previous investments) to $2.7 million. Our investment is accounted for on the equity method. Tatex accounts for its investment in APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm's initial gross production was approximately 60 million cubic feet, or MMcf, per day. Gross production during 2008 was approximately 83 MMcf and 433 Bbls of oil per day. Hess Corporation operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTTEP (20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex as a member of APICO) in the Phu Horm field is 0.7%. Estimated proved reserves from the Phu Horm field as of December 31, 2007, net to our interest, are 3.5 BCF of gas and 19,000 barrels of oil. Due to the fact that our ownership in the Phu Horm field is indirect and Tatex's investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information.

During the first quarter of 2008, we purchased a 5% ownership interest in Tatex Thailand III, LLC, or Tatex III, at a cost of $850,000. Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled by Wexford, an affiliate of ours. Tatex III owns a concession covering one million acres. The operator is currently conducting a 3-D seismic survey on this concession. During the nine months ended September 30, 2009, we paid $390,000 in cash calls bringing our total investment in Tatex III to $1.2 million.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates including those related to oil and natural gas properties, revenue recognition, income taxes and commitments and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements.

Oil and Natural Gas Properties. We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs are limited to the estimated future net revenues, after income taxes, discounted at 10% per year, from proven oil and natural gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs, if any, are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and natural gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves. Oil and natural gas properties not subject to amortization consist of the cost of undeveloped leaseholds and totaled $17.0 million at September 30, 2009 and $22.5 million at December 31, 2008. These costs are reviewed periodically by management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in its impairment assessment include our drilling results and those of other operators, the terms of oil and natural gas leases not held by production and available funds for exploration and development.

Ceiling Test. Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and costs, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, less income tax effects related to differences between the book and tax basis of the oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can give us a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. For instance, as a result of the drop in commodity prices on December 31, 2008 and subsequent reduction in our proved reserves, we recognized a ceiling test impairment of $272.7 million for the year ended December 31, 2008. If prices of oil, natural gas and natural gas liquids continue to decrease, we may be required to further write down the value of our oil and gas properties, which could negatively affect our results of operations.

Asset Retirement Obligations. We have obligations to remove equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and associated production facilities.

We account for abandonment and restoration liabilities under FASB ASC 410 which requires us to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, we increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements.

The fair value of the liability associated with these retirement obligations is determined using significant assumptions, including current estimates of the plugging and abandonment or retirement, annual inflations of these costs, the productive life of the asset and our risk adjusted cost to settle such obligations discounted using our credit adjustment risk free interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to the carrying amount of the related long-lived asset, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural gas assets, the costs to ultimately retire these assets may vary significantly from previous estimates.

Oil and Gas Reserve Quantities. Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell & Associates, Inc., Pinnacle Energy Services, LLC and to a lesser extent our personnel have prepared reserve reports of our reserve estimates at December 31, 2008 on a well-by-well basis for our properties.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows derived from these reserve estimates have been prepared in accordance with SEC guidelines. The accuracy of our reserve estimates is a function of many factors including the following:

• the quality and quantity of available data;

• the interpretation of that data;

• the accuracy of various mandated economic assumptions; and

• the judgments of the individuals preparing the estimates.

Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.

Income Taxes. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (a) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (b) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. Periodically, management performs a forecast of its taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established, if in management's opinion, it is more likely than not that some portion will not be realized. At December 31, 2008, a valuation allowance of $81.9 million had been provided for deferred tax assets based on the uncertainty of future taxable income.

Revenue Recognition. We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recorded at the end of the quarter after payment is received. Historically, our actual payments have not significantly deviated from our accruals.

Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. We are involved in certain litigation for which the outcome is uncertain. Changes in the certainty and the ability to reasonably estimate a loss amount, if any, may result in the recognition and subsequent payment of legal liabilities.

Derivative Instruments and Hedging Activities. We seek to reduce our exposure to unfavorable changes in oil prices by utilizing energy swaps and collars, or fixed-price contracts. We follow the provisions of FASB ASC 815, "Derivatives and Hedging." It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using established index prices and other sources. These values are based upon, among other things, futures prices, correlation between index prices and our realized prices, time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. We recognize any change in fair value resulting from ineffectiveness immediately in earnings. We currently have forward sales contracts in place for the remainder of 2009 and 2010 that are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815 and related pronouncements.

RESULTS OF OPERATIONS

Comparison of the Three Months Ended September 30, 2009 and 2008

We reported net income of $6,674,000 for the three months ended September 30, 2009, as compared to $14,107,000 for the three months ended September 30, 2008. This 53% decrease in period-to-period net income was due primarily to a 42% decrease in realized BOE prices to $53.34 from $92.19, partially offset by a 4% increase in net production to 416,000 BOE, a 46% decrease in lease operating expenses, a 21% decrease in general and administrative expenses and a 35% decrease in production taxes.

Oil and Gas Revenues. For the three months ended September 30, 2009, we reported oil and natural gas revenues of $22,173,000 as compared to oil and natural gas revenues of $36,907,000 during the same period in 2008. This $14,734,000, or 40%, decrease in revenues is primarily attributable to a 42% decrease in realized BOE prices to $53.34 from $92.19, partially offset by a 4% increase in net production to 416,000 BOE for the quarter ended September 30, 2009 from 400,000 BOE for the quarter ended September 30, 2008.

The following table summarizes our oil and natural gas production and related pricing for the three months ended September 30, 2009, as compared to such data for the three months ended September 30, 2008:

                                                     Three Months Ended
                                                       September 30,
                                                      2009         2008
             Oil production volumes (MBbls)               373         361
             Gas production volumes (MMcf)                161         135
             Liquid production volumes (gallons)          651         695
             Oil Equivalents (Mboe)                       416         400
             Average oil price (per Bbl)           $    56.62    $  95.08
             Average gas price (per Mcf)           $     3.09    $   9.91
             Average liquids price (per gallon)    $     0.82    $   1.75
             Oil equivalents (per Boe)             $    53.34    $  92.19

Lease Operating Expenses. Lease operating expenses, or LOE, not including production taxes decreased to $3,442,000 for the three months ended September 30, 2009 from $6,362,000 for the same period in 2008. This decrease is mainly a result of a decrease in contract labor expenses, a decrease in workovers, compressor and other equipment rentals and repairs, a decrease in the cost of chemicals and supplies and a decrease in personal property taxes. In addition, the three months ended September 30, 2009 included a net reduction to LOE of $369,000 as a result of insurance reimbursements related to hurricane repairs compared to $666,000 of unreimbursed expenses related to hurricane repairs in the three months ended September 30, 2008.

Production Taxes. Production taxes decreased to $2,586,000 for the three months ended September 30, 2009 from $3,970,000 for the same period in 2008. This decrease was primarily related to a 40% decrease in oil and gas revenues as a result of the decrease in the average realized BOE price received.

Depreciation, Depletion and Amortization. Depreciation, depletion and . . .