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 in the Bakken Shale, 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 2008 Highlights and Other 2008 Developments

• Revenues. Oil and natural gas revenues increased 23%, or $6,935,000, to $36,907,000 for the three months ended September 30, 2008 from $29,972,000 for the three months ended September 30, 2007.

• Net Income. Net income increased 11% to $14,107,000 for the three months ended September 30, 2008 from $12,701,000 for the three months ended September 30, 2007.

• Production. Production decreased 9% to 400,000 barrels of oil equivalent, or BOE, for the three months ended September 30, 2008 from 440,000 BOE for the three months ended September 30, 2007 due primarily to the impact of Hurricanes Gustav and Ike.

• Tatex Entities. During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex. The remaining interests in Tatex are owned by entities controlled by Wexford Capital, LLC, or Wexford, an affiliate of ours. 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 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 and individuals affiliated with Wexford.

• Windsor Bakken, LLC. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken are owned by entities controlled by Wexford. In 2006, Bakken acquired leases on undeveloped acreage in the Williston Basin areas of western North Dakota and eastern

• Reserves. As of December 31, 2007, we had 29.2 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately $821 million and associated standardized measure of discounted future net cash flows of approximately $668.3 million. Our total, proved reserve quantities were 86% oil at December 31, 2007.

2008 Production and Drilling Activity

During the three months ended September 30, 2008, our total net production was 361,000 barrels of oil, 135,000 thousand cubic feet of gas, or Mcf, and 695,000 gallons of liquids, for a total 400,000 BOE, compared to 404,000 barrels of oil, 218,000 Mcf of gas and no liquids, for a total 440,000 BOE, for the three months ended September 30, 2007. Our total net production averaged approximately 4,352 BOE per day during the three months ended September 30, 2008 compared to 4,787 BOE per day during the same period in 2007. This nine percent decrease is primarily due to the impact of Hurricanes Gustav and Ike.

WCBB. As of October 31, 2008, we had drilled eight wells, seven of which were producing and one was non-productive. We had also recompleted 43 wells. We do not intend to drill any more wells during 2008. We intend to recomplete approximately 50 existing wells during 2008.

Aggregate net production from the WCBB field during the three months ended September 30, 2008 was 270,000 BOE, or 2,935 BOE per day, approximately 96% of which was from oil and 4% of which was from natural gas. During October 2008, our average daily net production at WCBB was approximately 3,333 BOE, 99% of which was from oil and 1% of which was from natural gas. The increase in October production is primarily due to production being restored after Hurricanes Gustav and Ike.

East Hackberry Field. As of October 31, 2008 at East Hackberry, we had drilled five wells, all five of which were producing. We had also recompleted five existing wells as of that date. We do not intend to drill any more wells during 2008.

Aggregate net production from the East Hackberry field during the three months ended September 30, 2008 was approximately 44,000 BOE, or 481 BOE per day, 95% of which was from oil and 5% of which was from natural gas. During October 2008, our average daily net production at East Hackberry was approximately 844 BOE, 94% of which was from oil and 6% of which was from natural gas. The increase in October production is primarily due to production being restored after Hurricanes Gustav and Ike.

West Hackberry Field. Aggregate net production from the West Hackberry field during the three months ended September 30, 2008 was approximately 3,000 BOE, or 34 BOE per day. For the three days of production beginning on October 29, 2008 our average daily net production at West Hackberry was approximately 36 BOE. Production was not restored to the field after Hurricanes Gustav and Ike until October 29, 2008.

West Texas. On December 20, 2007, we completed the acquisition of strategic assets in West Texas in the Permian Basin for approximately $85 million, with an effective date of November 1, 2007. The final post-closing adjustments occurred on March 20, 2008, which was 90 days after the original closing date of December 20, 2007, and the purchase price was adjusted accordingly. The total adjusted purchase price for the assets was $83.8 million. Through this transaction, we acquired 4,100 net acres with production at the time of acquisition from 32 gross wells, predominately from the Wolfcamp formation. At December 31, 2007, Pinnacle Energy Services LLC, an independent petroleum engineering firm, estimated that proved reserves net to our interest in these assets were approximately 6.6 million BOE, of which 19.5% were classified as proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 92 gross well locations on 40-acre units. The proved reserves are located in the Wolfcamp and Spraberry formations, which are generally characterized as long-lived, with predictable production profiles. We expect that approximately 31 gross wells, including one well spud in 2007 and completed in 2008 and one Henry Petroleum operated well, will be drilled in 2008. The wells are expected to be drilled to approximately 10,400 feet at an estimated

average gross completed well cost of $2.0 million. As of October 31, 2008 at Permian, 30 gross wells have been drilled, including one well spud in 2007 and completed in 2008 and one Henry Petroleum operated well. Twenty seven of those wells have been completed, and three wells are awaiting completion. In addition, one well is currently being drilled in the field.

Aggregate net production from the Permian field during the three months ended September 30, 2008 was approximately 64,000 BOE, or 692 BOE per day. During October 2008, average daily net production at Permian was approximately 781 BOE, of which approximately 59% was oil, 25% was natural gas liquids and 16% was natural gas.

Bakken. As of October 31, 2008, we had participated, or committed to participate, in approximately 50 gross wells, which include 29 wells in Mountrail County, with an average working interest of 2.8%. Windsor Energy, the operator of our acreage, drilled and completed the first and second Windsor Energy operated wells. We own an approximately 15.5% working interest in the first well and approximately 3.9% working interest in the second well. Windsor Energy is now drilling its third operated well with the same rig. In addition, a second rig has been contracted and will commence drilling during November 2008. We currently hold approximately 17,660 net acres, which include approximately 4,660 acres in Mountrail County, in the Bakken play.

Aggregate net production from the Bakken play during the three months ended September 30, 2008 was approximately 19,000 BOE, or 202 BOE per day. For October 2008, average daily net production in Bakken was approximately 278 BOE.

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 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 $39,505,000 at September 30, 2008 and $37,278,000 at December 31, 2007. 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 write-down is required. Ceiling test impairment can give us a significant loss for a particular period; however, future depletion expense would be reduced. A future decline in oil and gas prices may result in an impairment of oil and gas properties.

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 Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations," or SFAS No. 143, 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 adjusted 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. and Pinnacle Energy Services, LLC have prepared reserve reports on approximately 79% of our reserve estimates on a well-by-well basis for our properties. Our personnel have prepared reserve reports on 21% of our reserve estimates.

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 the Securities and Exchange Commission, or 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 (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) 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, 2007, a valuation allowance of $9,750,000 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 may 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 SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, or SFAS 133. 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 SFAS 133, 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.

To mitigate the effects of commodity price fluctuations, we were party to forward sales contracts for the sale of 3,500 barrels of production per day for the months of January 2008 through May 2008 at a weighted average daily price of $70.29 per barrel before transportation costs. For June 2008, we had agreements to sell 3,500 barrels of production per day at a weighted average daily price of $71.69 per barrel before transportation costs. For the month of July 2008, we had agreements to sell 3,500 barrels of production per day at a weighted average daily price of $85.89 per barrel before transportation costs. For August 2008, we had agreements to sell 3,500 barrels of production per day at a weighted average daily price of $86.81 per barrel before transportation costs. For the period of September 2008 through December 2008, we have entered into forward sales contracts for the sale of 3,500 barrels of production per day during such period at a weighted average daily price of $86.60 per barrel before transportation costs. Under these agreements, we have committed to deliver approximately 75% of our estimated production for January through December 2008. For the period of January 2009 through December 2009, we entered into agreements to sell 3,000 barrels of production per day at a weighted average daily price of $89.06 per barrel before transportation costs. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase above the contracted prices. These contracts require physical delivery of production quantities and are exempted from the provisions of SFAS 133 as normal sales of production.

RESULTS OF OPERATIONS

Comparison of the Three Months Ended September 30, 2008 and 2007

We reported net income of $14,107,000 for the three months ended September 30, 2008, as compared to $12,701,000 for the three months ended September 30, 2007. This 11% increase in net income was due primarily to a 35% increase in realized BOE prices to $92.19 from $68.05 offset by a 9% decrease in net production to 400,000 BOE for the quarter ended September 30, 2008 from 440,000 BOE for the quarter ended September 30, 2007. This 9% decrease in net production is due to the impact of Hurricanes Gustav and Ike.

Oil and Gas Revenues. For the three months ended September 30, 2008, we reported oil, natural gas and liquid revenues of $36,907,000 as compared to oil and natural gas revenues of $29,972,000 during the same period in 2007. This $6,935,000, or 23%, increase in revenues is primarily attributable to a 35% increase in realized BOE prices to $92.19 from $68.05 offset by a 9% decrease in net production to 400,000 BOE for the quarter ended September 30, 2008 from 440,000 BOE for the quarter ended September 30, 2007.

The following table summarizes our oil and natural gas production and related pricing for the three months ended September 30, 2008, as compared to the three months ended September 30, 2007:

                                                    Three Months Ended
                                                      September 30,
                                                     2008        2007
             Oil production volumes (MBbls)             361         404
             Gas production volumes (MMcf)              135         218
             Liquid production volumes (Gallons)        695          -
             Oil Equivalents (Mboe)                     400         440

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