The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in Item 1A. "Risk Factors" and the section entitled "Cautionary Note Regarding Forward-Looking Statements" appearing elsewhere in this Annual Report on Form 10-K.
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 the Utica Shale in Eastern Ohio. During 2010, we acquired our initial acreage position in the Niobrara Formation of Northwestern Colorado and, during 2011, we acquired our initial acreage position in the Utica Shale in Eastern Ohio. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, a 21.4% equity interest in Diamondback Energy, Inc., or Diamondback, a NASDAQ Global Select Market listed company to which we contributed our Permian Basin oil and gas interests in October 2012 immediately prior to Diamondback's initial public offering, or the Diamondback IPO (see "Item 1. Business-Recent Developments-Contribution" above), 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. 2012 and 2013 Year to Date Highlights
• Oil and natural gas revenues increased 9% to $248.6 million for the year ended December 31, 2012 from $229.0 million for the year ended December 31, 2011.

• Production increased 10% to approximately 2,572,618 barrels of oil equivalent, or BOE, for the year ended December 31, 2012 from approximately 2,333,208 BOE for the year ended December 31, 2011.

• During 2012, we drilled 94 gross (71 net) wells, which included 23 gross (8.4 net) wells drilled by our operators in the Permian Basin, the Niobrara Formation and the Bakken Formation. In addition, 12 gross (one net) wells were drilled by another operator on our Utica Shale acreage during 2012. During 2012 we recompleted 94 gross (93 net) wells. Of our 94 new wells drilled, 69 were completed as producing wells and eight were non-productive and, at year end, 13 were waiting on completion and four were drilling.

• During 2011 and 2012, we acquired leasehold interests in approximately 137,000 gross (106,000 net) acres in the Utica Shale in Eastern Ohio, including the approximately 37,000 net acres acquired in December 2012. In February 2013, we acquired approximately 22,000 additional net acres in the Utica Shale. We spud our first well on our Utica Shale acreage in February 2012 and, as of February 15, 2013, had spud 16 wells, of which three were producing, seven had been completed, four were waiting on completion and two were being drilled.

• In October 2012, we contributed to Diamondback, prior to the closing of the Diamondback IPO, all of our oil and natural gas interests in the Permian Basin for shares of Diamondback common stock and a promissory note, which was repaid to us at the closing of the Diamondback IPO. As of October 23, 2012, following the closing of the Diamondback IPO and the underwriters' exercise in full of their option to purchase additional shares of common stock of Diamondback, we owned approximately 21.4% of Diamondback's outstanding common stock.

• In October and December of 2012, we issued a total of $300.0 million in aggregate principal amount of our 7.750% Senior Notes due 2020, resulting in net proceeds to us of approximately $290.3 million, a portion of which we used to repay all outstanding borrowings under our senior secured revolving credit facility. We intend to use the remaining net proceeds for general corporate purposes, which may include funding a portion of our 2013 capital development plan.

• In December of 2012, we completed an underwritten public offering of an aggregate of 11,750,000 shares of our common stock (including the partial exercise of an over-allotment option for 1,650,000 shares granted to the underwriters, which option was exercised to the extent of 750,000 shares). In January 2013, the underwriters exercised their option to purchase the remaining 900,000 shares of our common stock to cover over-allotments. We received net proceeds of approximately $460.7 million through these sales of our common stock. We used approximately $372.0 million to fund our acquisition of approximately 37,000 net acres in the Utica Shale in Eastern Ohio and we intend to use the remaining net proceeds for general corporate purposes, which may include funding a portion of our 2013 capital development plan.

• In February 2013, we completed an underwritten public offering of an aggregate of 8,912,500 shares of our common stock (including the exercise in full of an over-allotment option for 1,162,500 shares granted to the underwriters). We received net proceeds of approximately $325.8 million from this offering. We used approximately $220.4 million to fund our acquisition of approximately 22,000 net acres in the Utica Shale in Eastern Ohio and we intend to use the remaining net proceeds for general corporate purposes, which may include funding a portion of our 2013 capital development plan.

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. 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 the 12-month unweighted average of the first-day-of-the-month price for the period 2012, 2011 and 2010, 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, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties 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 $626.3 million at December 31, 2012 and $138.6 million at December 31, 2011. These costs are reviewed quarterly 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 the 12-month unweighted average of the first-day-of-the-month price for the period January - December of the applicable year beginning with 2009, 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, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, 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 decline, we may be required to further write down the value of our oil and gas properties, which could negatively affect our results of operations. No ceiling test impairment was required for the year ended December 31, 2012. 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. NSAI, Ryder Scott and to a lesser extent our personnel have prepared reserve reports of our reserve estimates at December 31, 2012 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. Therefore, 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, 2012, a valuation allowance of $4.6 million had been provided for state net operating loss and federal tax credit deferred tax assets based on the uncertainty these assets may be realized.
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. Investments-Equity Method. Investments in entities greater than 20% and less than 50% are accounted for under the equity method. Under the equity method, our share of investees' earnings or loss is recognized in the statement of operations. In accordance with FASB ASC 825, "Financial Instruments," we have elected the fair value option of accounting for our equity method investment in Diamondback's stock. At the end of each reporting period, the quoted closing market price of Diamondback's stock is multiplied by the total shares owned by us and the resulting gain or loss is recognized in (income) loss from equity method investments in the consolidated statements of operations.
We review our investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, we recognize an impairment provision. There was no impairment of equity method investments at December 31, 2012 or 2011.
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," as amended. 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.
To mitigate the effects of commodity price fluctuations, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January 2010 through February 2010. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials. In November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For January 2012 through February 2012, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through July 2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from August 2012 through December 2012, we entered into fixed price swaps for 4,000 barrels of oil per day at a weighted average price of $107.29 per barrel. For the period from January 2013 through December 2013, we have entered into fixed price swaps for 5,000 barrels of oil per day at a weighted average price of $100.90 per barrel. Under the 2011 contracts, we hedged approximately 31% of our 2011 production. Under the 2012 contracts, we hedged approximately 46% of our 2012 production. Under the 2013 contracts, we have hedged approximately 23% of our estimated 2013 production. 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. In addition, these arrangements may limit the benefit to us of increases in the price of oil. These forward sales contacts and fixed price swaps are

accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815, "Derivatives and Hedging," and related pronouncements.
RESULTS OF OPERATIONS

Results of Operations
The markets for oil and natural gas have historically been, and will continue to
be, volatile. Prices for oil and natural gas may fluctuate in response to
relatively minor changes in supply and demand, market uncertainty and a variety
of factors beyond our control.
The following table presents our production volumes, average prices received and
average production costs during the periods indicated:
                                              2012              2011              2010
Production Volumes:
Oil (MBbls)                                    2,323             2,128             1,777
Gas (MMcf)                                     1,108               878               788
Natural gas liquids (MGal)                     2,714             2,468             2,821
Oil equivalents (MBOE)                         2,573             2,333             1,976
Average Prices:
Oil (per Bbl)                             $   104.46   (1)  $   104.33   (1)  $    68.29   (1)
Gas (per Mcf)                             $     2.91        $     4.37        $     4.40
Natural gas liquids (per Gal)             $     0.98        $     1.25        $     1.00
Oil equivalents (per BOE)                 $    96.63        $    98.13        $    64.61
Production Costs:
Average production costs (per BOE)        $     9.45        $     8.96        $     8.92
Average production taxes (per BOE)        $    11.43        $    11.29        $     7.07
Total production costs and production
taxes (per BOE)                           $    20.88        $    20.25        $    15.99


_____________________

January - December 2012 $ 108.31
January - December 2011 $  86.96
January - December 2010 $  57.55

Excluding the net effect of fixed price swaps, the average oil price for 2012 would have been $106.11 per barrel of oil and $98.12 per BOE. The total volume hedged for 2012 represented approximately 46% of our total sales volumes for the year. Excluding the net effect of fixed price swap contracts, the average oil price for 2011 would have been $107.13 per barrel of oil and $100.68 BOE. The total volume hedged for 2011 represented approximately 31% of our total sales volumes for the year. Excluding the net effect of forward sales contracts, the average oil price for 2010 would have been $78.12 per barrel of oil and $73.45 per BOE. The total volume hedged for 2010 represented approximately 45% of our total sales volumes for the year.
From 2011 to 2012, our net equivalent oil production increased 10% from 2,333,208 BOE to 2,572,618 BOE due to the results of our 2012 drilling and recompletion activities. From 2010 to 2011, our net equivalent oil production also increased 18% from 1,975,576 BOE to 2,333,208 BOE due to the results of our 2011 drilling and recompletion activities. We currently estimate that our 2013 production will be between 7,800,000 and 8,100,000 BOE. However, such estimate may change based on a change in our expected drilling and recompletion activities or the changing economic climate and unforeseen events, such as hurricanes.

Comparison of the Years Ended December 31, 2012 and December 31, 2011 We reported net income of $68,371,000 for the year ended December 31, 2012 as compared to net income of $108,422,000 for the year ended December 31, 2011. This 37% decrease in period-to-period net income was due primarily to a 2% decrease in realized BOE prices to $96.63 for the year ended December 31, 2012, a 16% increase in lease operating expenses, a 71% increase in general and administrative expenses, a 12% increase in production taxes, an approximately $6.0 million increase in interest expense, a $3.5 million loss on the disposal of our Belize properties, net of tax, and a $24.2 million increase in income taxes from continuing and discontinued operations, partially offset by a 10% increase in net production to 2,572,618 BOE, a gain on sale of assets of $7.3 million and income from equity method investments of $8.3 million.
Oil and Gas Revenues. For the year ended December 31, 2012, we reported oil and natural gas revenues of $248,601,000 as compared to oil and natural gas revenues of $228,953,000 during 2011. This $19,648,000, or 9%, increase in revenues was primarily attributable to a 10% increase in net production to 2,572,618 BOE from 2,333,208 BOE, partially offset by a 2% decrease in realized BOE prices to $96.63 from $98.13, for the year ended December 31, 2012 as compared to the year ended December 31, 2011.
The following table summarizes our oil and natural gas production and related pricing for the years ended December 31, 2012 and December 31, 2011:

                                                   Year Ended
                                                  December 31,
                                                2012        2011
Oil production volumes (MBbls)                   2,323       2,128
Gas production volumes (MMcf)                    1,108         878
. . .