Form 10-Q

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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. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

As of May 5, 2010, there were 74,698,767 shares outstanding of the registrant’s common stock, par value $0.00001.

Operations. W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T” or the “Company,” is an independent oil and natural gas producer, active in the acquisition, exploitation, exploration and development of oil and natural gas properties in the Gulf of Mexico.

Interim Financial Statements. The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) for interim financial information and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the condensed consolidated financial statements do not include all of the information and footnote disclosures required by GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. The accompanying financial statements for the three months ended March 31, 2010 include a reduction of hurricane remediation, facilities and workover expenses totaling approximately $5.1 million related to prior years. The amounts were not deemed material with respect to such prior years or the anticipated results and the trend of earnings for fiscal year 2010. Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.

Reclassifications. Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation.

Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Ceiling Test Impairment. The carrying amount of our oil and natural gas properties was written down by $218.9 million as of March 31, 2009 through application of the full cost ceiling limitation as prescribed by the SEC, primarily as a result of lower natural gas prices at March 31, 2009, as compared to December 31, 2008. Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation, including a reclassification of $5.2 million of costs previously included in impairment of oil and natural gas properties during the quarter ended March 31, 2009 to lease operating expenses. The ceiling test impairment was subsequently increased by $13.9 million in the fourth quarter of 2009 resulting from further analysis of our March 31, 2009 ceiling test impairment calculation. As such, operating income, net income and our basic and diluted loss per common share for the first quarter of 2009 have been adjusted as well. We did not have a ceiling test impairment during the quarter ended March 31, 2010.

Effective for our annual reporting period ended December 31, 2009, we adopted certain amendments to the Extractive Activities—Oil and Gas Topic of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (the “Codification”) that updated and aligned the FASB’s reserve estimation and disclosure requirements for oil and natural gas companies with the reserve estimation and disclosure requirements that were adopted by the SEC in December 2008. In accordance with the new rules, we use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period, rather than end-of-period commodity prices, when estimating quantities of proved reserves. Additionally, the estimated future net revenues used to calculate the ceiling test are based on the 12-month average commodity price for each product. Also, because it is our policy to use end-of-period reserves in the determination of quarterly depletion, such expense is calculated using proved reserves that were determined in accordance with the new rules. Refer to our Annual Report on Form 10-K for the year ended December 31, 2009 for additional information about the impact of these new requirements on our oil and natural gas reserves and financial statements.

In January 2010, the FASB issued certain amendments to the Fair Value Measurements and Disclosures Topic of the Codification that require additional disclosures about amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons therefor. Additionally, entities are now required to present separately information about purchases, sales, issuances and settlements in the reconciliation of fair value measurements using significant unobservable (Level 3) inputs. The amendments also clarified that entities should provide fair value measurement disclosures for each class, or subset, of assets or liabilities within a line item in the statement of financial position, and entities should disclose information about inputs and valuation techniques for Level 2 and Level 3 fair value measurements, whether recurring or nonrecurring. These amendments are effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances and settlements in the reconciliation of fair value measurements using Level 3 inputs, which are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal years. The adoption of these amendments to the Codification did not have an impact on the Company’s financial position, cash flows or results of operations.

Our asset retirement obligations primarily represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. A summary of our asset retirement obligations is as follows (in thousands):

At March 31, 2010 and December 31, 2009, borrowings outstanding under our 8.25% Senior notes (the “Notes”) were $450.0 million, all of which are classified as long-term. Also at March 31, 2010 and December 31, 2009, we had no amounts outstanding under our committed revolving loan facility and we had $0.7 million of letters of credit outstanding under the Third Amended and Restated Credit Agreement, as amended (the “Credit Agreement”) which is described below.

Borrowings under the Credit Agreement are secured by our oil and natural gas properties. Availability under the Credit Agreement is subject to a semi-annual borrowing base redetermination (March and September) set at the discretion of our lenders. The amount of the borrowing base is calculated by our lenders based on their valuation of our proved reserves and their own internal criteria. In April 2010, our borrowing base under the Credit Agreement was reaffirmed by our lenders at $405.5 million. Also in April 2010, we borrowed $142.5 million under our revolving loan facility.

Under the Credit Agreement, we are subject to various financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio and a maximum leverage ratio, as such ratios are defined in the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement as of March 31, 2010.

The Notes bear interest at a fixed rate of 8.25%, with interest payable semi-annually in arrears on June 15 and December 15. At March 31, 2010 and December 31, 2009, the estimated fair value of the Notes was approximately $414.0 million and $432.0 million, respectively, based on quoted prices. The estimated annual effective interest rate on the Notes is 8.4%.

We measure the fair value of our derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The inputs used in measuring the fair value of our derivative financial instruments consist of market-based or independently-sourced market parameters, including but not limited to forward curves for oil, natural gas and interest rates, and volatilities. In addition to market information, the models also incorporate the contractual terms of the instruments. The fair values of our derivative assets and liabilities include adjustments for credit risk and were $5.0 million and $8.1 million, respectively, at March 31, 2010, and $0.1 million and $9.9 million, respectively, at December 31, 2009. For additional details about our derivative financial instruments, refer to Note 6. The estimated fair value of the Notes, as disclosed in Note 4, was based on quoted prices, which are classified as Level 1 inputs.

We account for derivative contracts in accordance with the Derivatives and Hedging Topic of the Codification, which requires each derivative to be recorded on the balance sheet as an asset or a liability at its fair value. Changes in a derivative’s fair value are required to be recognized currently in earnings unless specific hedge accounting criteria are met at the time we enter into a derivative contract.

Our market risk exposure relates primarily to commodity prices and interest rates. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our credit facility. We do not enter into derivative instruments for speculative trading purposes. Our derivative instruments currently consist of commodity option contracts, a commodity swap contract and an interest rate swap contract. The Company is exposed to credit loss in the event of nonperformance by the counterparties; however, none is currently anticipated.

Commodity Derivatives. We have entered into a limited number of commodity option contracts and a commodity swap contract to help manage our exposure to commodity price risk from sales of oil and natural gas during the fiscal years ending December 31, 2010 and 2011. We have elected not to designate our commodity derivatives as hedging instruments. While these contracts are intended to reduce the effects of volatile oil and natural gas prices, they may also limit future income from favorable price movements. As of March 31, 2010, our open commodity derivatives were as follows:

Changes in the fair value of our commodity derivative contracts are recognized currently in earnings. For the three months ended March 31, 2010, we recognized a gain of $6.2 million related to a change in the fair value of our commodity derivatives. We did not have any open commodity derivative positions during the three months ended March 31, 2009.

At March 31, 2010, $5.0 million was included in prepaid expenses and other assets, $4.2 million was included in accrued liabilities and $1.1 million was included in other liabilities related to our commodity derivative contracts. At December 31, 2009, $0.1 million was included in prepaid expenses and other assets and $5.5 million was included in accrued liabilities related to our commodity derivative contracts.

Interest Rate Swap. We have one interest rate swap contract outstanding with a fixed interest rate of 5.21%, which expires in August 2010. Initially, this swap was designated as a hedge of the floating-rate interest payments on our Tranche B term loan facility. However, as a result of payments on the loan and changes to the swap contract, hedge accounting was discontinued completely in 2007. Changes in fair value subsequent to the discontinuation of hedge accounting have been immediately recognized in earnings. As of March 31, 2010, the total notional amount of our swap was $146.3 million.

For the three months ended March 31, 2010 and 2009, we recognized a loss of $0.3 million and $0.4 million, respectively, related to a change in the fair value of our interest rate swap.

At March 31, 2010 and December 31, 2009, the fair value of our interest rate swap was $2.8 million and $4.4 million, respectively. Both amounts were included in accrued liabilities on the respective dates.

At March 31, 2010, we had a federal income tax receivable of $84.5 million, which is comprised principally of net operating loss carrybacks from 2008 to 2007 of $8.9 million and from 2009 to 2004, 2005 and 2007 of $22.3 million, $42 million and $14.1 million, respectively. Income tax expense of $4.0 million was recorded during the three months ended March 31, 2010 compared to an income tax benefit of $24.0 million for the same period of 2009. Our effective tax rate for the quarter ended March 31, 2010 was approximately 8.7% and primarily reflects a decrease in our valuation allowance for our deferred tax assets in addition to adjustments for prior year taxes and other discrete items. Forecasted taxable income in 2010 has allowed us to reduce a portion of our valuation allowance. Our effective tax rate for the quarter ended March 31, 2009 was approximately 8.9% and primarily reflected the effect of a valuation allowance for our deferred tax assets.

During the third quarter of 2008, Hurricane Ike, and to a much lesser extent Hurricane Gustav, caused property damage and disruptions to our exploration and production activities. We currently have insurance coverage for named windstorms but we do not carry business interruption insurance. Our insurance policies in effect on the occurrence dates of Hurricanes Ike and Gustav had a retention of $10 million per occurrence that must be satisfied by us before we are indemnified for losses. In the fourth quarter of 2008, we satisfied our $10 million retention requirement for Hurricane Ike in connection with two platforms that were toppled and were deemed total losses. Our insurance coverage policy limits at the time of Hurricane Ike were $150 million for property damage due to named windstorms (excluding certain damage incurred at our marginal facilities) and $250 million for, among other things, removal of wreckage if mandated by any governmental authority. The damage we incurred as a result of Hurricane Gustav was well below our retention amount.

Included in lease operating expenses for the three months ended March 31, 2010 is a reduction of $6.3 million related to amounts approved for payment under our insurance policies and revisions to previous estimates (see Item 1 Basis of Presentation – Note 1 - Interim Financial Statements) of hurricane remediation costs incurred in connection with Hurricanes Ike and Gustav. Included in lease operating expenses for the three months ended March 31, 2009 are hurricane remediation costs of $10.2 million related to Hurricanes Ike and Gustav that were either not yet approved for payment or were not covered by insurance.

We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs as a result of hurricane damage when we deem those to be probable of collection. Our assessment of probability considers the review and approval of such costs by our insurance underwriters’ adjuster. Claims that have been processed in this manner have been paid on a timely basis.

We have also recognized an insurance receivable to the extent our insurance underwriters’ adjuster has reviewed our work plans and other information related to plugging and abandonment activities that were accelerated by Hurricane Ike and has indicated that our insurance policies provide coverage for such costs and such costs are within policy limits.

Below is a reconciliation of our insurance receivables from December 31, 2009 to March 31, 2010 (in thousands):

At March 31, 2010 and December 31, 2009, $2.4 million and $1.3 million, respectively, of remediation costs and $27.5 million and $29.2 million, respectively, related to the plugging and abandonment of wells and dismantlement of facilities damaged by Hurricane Ike are included in insurance receivables. We expect that our available cash and cash equivalents, cash flow from operations and the availability under our credit facility will be sufficient to meet any necessary expenditures that may exceed our insurance coverage for damages incurred as a result of Hurricanes Ike and Gustav.

We recognize compensation cost for share-based payments to employees and non-employee directors over the period during which the recipient is required to provide service in exchange for the award, based on the fair value of the equity instrument on the date of grant. A summary of share activity pursuant to our share-based payment plans for the quarter ended March 31, 2010, is as follows:

At March 31, 2010, the composition of our nonvested shares outstanding, by year granted, was as follows:

At March 31, 2010, there were 1,900,436 shares of common stock available for award under the Long-Term Incentive Compensation Plan and 618,891 shares of common stock available for award under the Directors Compensation Plan.

During the three months ended March 31, 2010 and 2009, total compensation expense under share-based payment arrangements was $1.0 million and $1.6 million, respectively. As of March 31, 2010, there was $5.3 million of total unrecognized share-based compensation expense related to restricted shares issued. Such amount is expected to be recognized in the period beginning April 2010 and ending April 2012.

In accordance with the Earnings Per Share Topic of the Codification, effective January 1, 2009, the Company adopted certain amendments to the accounting principles relating to its calculation of earnings (loss) per share. The amendments provide that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of earnings per share under the two-class method. The adoption of these amendments did not have an effect on our basic and diluted loss per common share for the three months ended March 31, 2009.

The following table presents the calculation of basic earnings (loss) per common share for the three months ended March 31, 2010 and 2009 (in thousands, except per share amounts):

Diluted earnings (loss) per common share is the same as basic earnings (loss) per common share because the nonvested shares outstanding during the periods are anti-dilutive.

During the three months ended March 31, 2010 and 2009, we paid regular cash dividends of $0.03 per common share. On May 3, 2010, our board of directors declared a cash dividend of $0.03 per common share, payable on June 23, 2010 to shareholders of record on May 26, 2010.

We are a party to various pending or threatened claims and complaints seeking damages or other remedies concerning our commercial operations and other matters in the ordinary course of our business. In addition, claims or contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters occurring subsequent to our sale of properties. In certain cases, we have indemnified the sellers of properties we have acquired, and in other cases, we have indemnified the buyers of properties we have sold. We are also subject to federal and state administrative proceedings conducted in the ordinary course of business. Although we can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, management believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

On April 7, 2010, we entered into a Purchase and Sale Agreement (“PSA”) with Total E&P USA, Inc. (“Total”) to acquire all of Total’s interest, including production platforms and facilities, in three federal offshore lease blocks located in the Gulf of Mexico for a purchase price of $150 million, subject to customary closing adjustments, with an effective date of January 1, 2010. The transaction closed on April 30, 2010, with our wholly-owned subsidiary, W&T Energy VI, LLC (“Energy VI”) as purchaser. The purchase price was adjusted for, among other things, net revenue and operating expenses from the effective date to the closing date and a down payment of $7.5 million, resulting in $117.5 million paid at closing. This acquisition was funded from cash on hand. In accordance with the PSA, Energy VI obtained unsecured surety bonds in favor of the Minerals Management Service (“MMS”) to secure the asset retirement obligations with respect to the Total assets. The PSA provides for annual increases in the required security for the asset retirement obligations. To satisfy the annual increases, Energy VI granted an overriding royalty from production of the acquired properties, payable to an escrow agent. As long as the required security amount then in effect is met, the payments under the overriding royalty will be promptly released to us by the escrow agent. We are currently in compliance with the required security amount.

The properties acquired from Total are producing interests with future development potential, and include a 100% working interest in Mississippi Canyon block 243 (“Matterhorn”) and a 64% working interest in Viosca Knoll blocks 822 and 823 (“Virgo”). The estimated proved oil and natural gas reserves on the effective date (determined using the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period) were 11.6 million barrels of oil equivalent (“Boe”), or 69.7 billion cubic feet equivalent (“Bcfe”) of natural gas, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. The reserves acquired were estimated as 64% oil and 36% natural gas.

The net operating loss carryback amounts related to 2009, which totaled $78.4 million, were received from the United States Treasury after the end of the first quarter of 2010. See Note 7.

The following discussion and analysis should be read in conjunction with our accompanying unaudited condensed consolidated financial statements and the notes to those financial statements included in Item 1 of this Quarterly Report on Form 10-Q. The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act, that involve risks, uncertainties and assumptions. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Certain factors that may affect our financial condition and results of operations are discussed in Item 1A “Risk Factors” and Item 7A “Quantitative and Qualitative Disclosures About Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2009 and may be discussed or updated from time to time in subsequent reports filed with the SEC. We assume no obligation, nor do we intend, to update these forward-looking statements. Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries.

W&T is an independent oil and natural gas producer focused in the Gulf of Mexico. W&T has grown through acquisitions, exploitation and exploration and currently holds working interests in approximately 77 producing fields in federal and state waters. The majority of our daily production is derived from wells we operate.

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil and natural gas production and the price that we receive for such production. Our production volume for March was comprised of approximately 49% oil and 51% natural gas, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. During the three months ended March 31, 2010, our combined total production of oil and natural gas was approximately 6.5% lower compared to the same period in 2009.

Oil and natural gas prices have been and are expected to remain volatile. The Henry Hub spot price for natural gas was $3.93 per MMBtu as of March 31, 2010, representing a decrease of 32.1% from $5.79 per MMBtu at the end of 2009. We are expecting continued weakness in natural gas prices unless demand for natural gas increases as a result of a strong economic recovery, or there is reduced drilling activity or forced production shut-ins. There is also a risk that, as a result of the success of exploration and development activities in the shale areas coupled with the availability of increasing amounts of liquefied natural gas (LNG), the supply of natural gas will offset or mitigate the impact of natural gas shut-ins or demand increases resulting from improved economic conditions. Neither the rig count nor commodity prices, especially for natural gas, are currently expected to recover in the immediate future to levels reached during peak activity levels in 2008.

The West Texas Intermediate posted price for oil was $80.25 per barrel as of March 31, 2010, representing an increase of 5.6% from $76.00 per barrel at the end of 2009. Although improved, crude oil prices remain far below the all-time high of $147 per barrel reached in July 2008. However, with the recovery in demand for oil in several key growing markets, specifically China and India, longer-term forecasts for oil demand, and therefore oil prices, have improved.

During the three months ended March 31, 2010, the average realized sales prices of our oil and natural gas were 92.8% and 5.9% higher, respectively, than the comparable average realized sales prices during the same period in 2009, which contributed to higher cash provided by operating activities in the 2010 period. Declines in oil and natural gas prices after March 31, 2010, if those were to occur, would negatively impact our future oil and natural gas revenues, earnings and liquidity, and could result in ceiling test impairments of the carrying value of our oil and natural gas properties, issues with financial ratio compliance, and a reduction of the borrowing base associated with our credit agreement. Such declines, if those were to occur, may limit the willingness of financial institutions and investors to provide borrowings or capital to us and others in the oil and natural gas industry.

The following tables set forth selected financial and operating data for the periods indicated (all values are net to our interest unless indicated otherwise):

Three Months Ended March 31, 2010 Compared to the Three Months Ended March 31, 2009

Revenues. Total revenues increased $52.2 million to $169.6 million for the three months ended March 31, 2010 as compared to the same period in 2009. Oil revenues increased $61.9 million and natural gas revenues decreased $9.7 million. The oil revenue increase was primarily attributable to a 92.8% increase in the average realized oil sales price to $69.95 per barrel for the three months ended March 31, 2010 from $36.29 per barrel for the same period in 2009, as well as a 13.3% increase in sales volumes. The sales volume increase for oil is primarily attributable to our successful exploration and development efforts, partially offset by a 0.2 Bbls decrease resulting from property sales as previously discussed. The decrease in natural gas revenue resulted from a 20.6% decrease in sales volumes, including 2.4 Bcf from property sales as previously discussed and natural reservoir declines, partially offset by a 5.9% increase in the average realized natural gas sales price to $5.38 per Mcf in the 2010 period from $5.08 per Mcf in the 2009 period.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, hurricane remediation costs and insurance reimbursements of hurricane remediation costs, decreased to $1.77 per Mcfe during the three months ended March 31, 2010 from $2.35 per Mcfe during the three months ended March 31, 2009. On a nominal basis, lease operating expenses decreased $14.9 million to $35.4 million during the three months ended March 31, 2010, compared to the same period in 2009. Included in lease operating expenses for the three months ended March 31, 2010 is a reduction of $6.3 million related to amounts approved for payment under our insurance policies and revisions to previous estimates (see Item 1 Basis of Presentation – Note 1 - Interim Financial Statements) of hurricane remediation costs incurred in connection with Hurricanes Ike and Gustav. Included in lease operating expenses for the three months ended March 31, 2009 are hurricane remediation costs of $10.2 million related to Hurricanes Ike and Gustav that were either not yet approved for payment or were not covered by insurance. Lease operating expenses will be offset in future periods to the extent that additional costs are incurred and approved for payment under our insurance policies. Decreases in base lease operating expenses and facility expenditures of $6.6 million and $2.9 million, respectively, were more than offset by increases in insurance and workover costs of $3.2 million and $7.9 million, respectively. The decrease in base lease operating expenses primarily reflects the sale of certain properties in 2009 as described above. The increase in workover costs is related to numerous projects undertaken during the three months ended March 31, 2010 to stimulate and restore production at various wells.

Production taxes. Production taxes decreased to $0.2 million for the three months ended March 31, 2010 from $0.7 million for the same period in 2009 primarily due to the sale of one of our fields in Louisiana state waters in the second quarter of 2009 and lower production from fields in state waters of Texas and Louisiana in 2010. Most of our production is from federal waters where there are no production taxes.

Gathering and transportation costs. Gathering and transportation costs increased to $4.6 million for the three months ended March 31, 2010 from $2.6 million for the same period in 2009 primarily due to an increase in throughput of natural gas liquids and an increased ownership interest in one of our gas processing facilities.

Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion (“DD&A”) decreased to $69.2 million for the three months ended March 31, 2010 from $91.5 million for the same period in 2009. DD&A decreased due to a lower depreciable base (including our estimate of the cost of asset retirement obligations) and lower production of oil and natural gas, partially offset by lower oil and natural gas reserves, compared to 2009. The decreases in our depreciable base reflect the sale of certain oil and natural gas fields in the second and fourth quarters of 2009. The decrease in our depreciable base also reflects lower future development costs due to the write-off of certain proved undeveloped reserves at the end of 2009 in connection with new reserve reporting requirements for oil and natural gas companies enacted by the SEC and the FASB. On a per Mcfe basis, DD&A was $3.47 for the three months ended March 31, 2010, compared to $3.61 for the year ended December 31, 2009 and $4.27 for the three months ended March 31, 2009.

Impairment of oil and natural gas properties. At March 31, 2009, we recorded a ceiling test impairment of our oil and natural gas properties of $218.9 million through application of the full cost ceiling limitation as prescribed by the SEC, primarily as a result of a further decline in natural gas prices at March 31, 2009 as compared to December 31, 2008. We did not have a ceiling test impairment during the quarter ended March 31, 2010.

General and administrative expenses. General and administrative expenses (“G&A”) decreased to $10.4 million for the three months ended March 31, 2010 from $11.4 million for the same period in 2009, primarily due to decreases in the number of employees, incentive compensation expense and increased administrative services billed to the buyer of certain properties, partially offset by higher legal fees and reduced overhead charges billed to joint operators. On a per Mcfe basis, G&A was $0.52 per Mcfe for the three months ended March 31, 2010, compared to $0.53 per Mcfe for the same period in 2009.

Derivative gain/loss. For the three months ended March 31, 2010, our derivative gain of $5.9 million consisted of a gain of $6.2 million related to a change in the fair value of our commodity derivatives, offset by a loss of $0.3 million related to a change in the fair value of our interest rate swap. For the three months ended March 31, 2009, our derivative loss of $0.4 million related entirely to a change in the fair value of our interest rate swap. For additional details about our derivatives, refer to Item 1 Financial Statements – Note 6 – Derivative Financial Instruments.

Interest expense. Interest expense incurred decreased to $10.9 million for the three months ended March 31, 2010 from $12.5 million for the three months ended March 31, 2009 primarily due to lower interest rates and lower amounts of borrowings outstanding during the 2010 period. During the 2010 and 2009 periods, $1.4 million and $1.8 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties.

Income tax expense/benefit. Income tax expense increased to $4.0 million for the three months ended March 31, 2010 from an income tax benefit of $24.0 million for the same period of 2009. Our effective tax rate for the three months ended March 31, 2010 was approximately 8.7% and primarily reflects a decrease in our valuation allowance for our deferred tax assets in addition to adjustments for prior year taxes and other discrete items. Forecasted taxable income in 2010 has allowed us to reduce a portion of our valuation allowance. For 2009, the income tax benefit resulted from a pre-tax loss. Our effective tax rate for the three months ended March 31, 2009 was approximately 8.9% and primarily reflected the effect of a valuation allowance for our deferred tax assets.

Our primary liquidity needs are to fund capital expenditures to allow us to replace our oil and natural gas reserves, repay outstanding borrowings and make related interest payments and to fund strategic property acquisitions. We have funded our capital expenditures, including acquisitions, with cash on hand, cash provided by operations, securities offerings and bank borrowings. These sources of liquidity have historically been sufficient to fund our ongoing cash requirements.

Cash flow and working capital. Net cash provided by operating activities for the three months ended March 31, 2010 was $87.0 million, compared to net cash provided by operating activities of $29.2 million for the comparable period in 2009. Net cash used in investing activities totaled $38.7 million and $123.5 million during the first three months of 2010 and 2009, respectively, which primarily represents our investments in oil and natural gas properties. At March 31, 2010, we had a cash balance of $84.2 million and we had $404.8 million of undrawn capacity under the revolving portion of the Credit Agreement. We believe that cash provided by operations, borrowings available under our revolving loan facility and other external sources of liquidity should be sufficient to fund our ongoing cash requirements.

Although our combined total production of oil and natural gas during the three months ended March 31, 2010 was approximately 6.5% lower compared to the same period in 2009, our combined average realized sales price was 55.1% higher in the 2010 period, which contributed to higher cash provided by operating activities in 2010. During the three months ended March 31, 2010, the average realized sales prices of our oil and natural gas were $69.95 per barrel and $5.38 per Mcf, respectively. Oil and natural gas prices have been and are expected to remain volatile. The Henry Hub spot price for natural gas was $3.93 per MMBtu as of March 31, 2010, representing a decrease of 32.1% from $5.79 per MMBtu at the end of 2009. The West Texas Intermediate posted price for oil was $80.25 per barrel as of March 31, 2010, representing an increase of 5.6% from $76.00 per barrel at the end of 2009.

From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our credit facility. During the quarter ended March 31, 2010, we entered into commodity option contracts relating to approximately 4 Bcfe and 7 Bcfe of our anticipated production in 2010 and 2011, respectively. As of March 31, 2010, our derivative instruments consisted of commodity option contracts and a commodity swap contract relating to approximately 14 Bcfe of our anticipated production during the remainder of 2010 and approximately 7 Bcfe of our anticipated production in 2011. We also have an interest rate swap contract that serves to manage the risk associated with the floating rate of interest on our revolving loan facility. For additional details about our derivatives, refer to Item 1 Financial Statements – Note 6 – Derivative Financial Instruments.

Hurricane Remediation and Insurance Claims. During the third quarter of 2008, Hurricane Ike, and to a much lesser extent Hurricane Gustav, caused property damage and disruptions to our exploration and production activities. We currently have insurance coverage for named windstorms but we do not carry business interruption insurance. Our insurance policies in effect on the occurrence dates of Hurricanes Ike and Gustav had a retention of $10 million per occurrence that must be satisfied by us before we are indemnified for losses. In the fourth quarter of 2008, we satisfied our $10 million retention requirement for Hurricane Ike in connection with two platforms that were toppled and were deemed total losses. Our insurance coverage policy limits at the time of Hurricane Ike were $150 million for property damage due to named windstorms (excluding certain damage incurred at our marginal facilities) and $250 million for, among other things, removal of wreckage if mandated by any governmental authority. The damage we incurred as a result of Hurricane Gustav was well below our retention amount.

For a summary of our hurricane remediation costs related to lease operating expenses incurred during the three months ended March 31, 2010 and 2009, refer to Item 1 Financial Statements – Note 8 – Hurricane Remediation and Insurance Claims. Lease operating expenses will be offset in future periods to the extent that additional costs are incurred and approved for payment under our insurance policies.

To the extent our insurance underwriters’ adjuster has reviewed work plans and other information provided by us in connection with our plugging and abandonment activities scheduled to be completed and that were accelerated by Hurricane Ike, and has indicated that our insurance policies provide coverage for such costs and they are within policy limits, we have recognized an insurance receivable.

At March 31, 2010 and December 31, 2009, $2.4 million and $1.3 million, respectively, of remediation costs and $27.5 million and $29.2 million, respectively, related to the plugging and abandonment of wells and dismantlement of facilities damaged by Hurricane Ike are included in insurance receivables. Refer to Item 1 Financial Statements – Note 8 – Hurricane Remediation and Insurance Claims for a reconciliation of our insurance receivables from December 31, 2009 to March 31, 2010. We expect that our available cash and cash equivalents, cash flow from operations and the availability under our credit facility will be sufficient to meet any necessary expenditures that may exceed our insurance coverage for damages incurred as a result of Hurricanes Ike and Gustav.

Due to increased insurance claims in recent years associated with hurricanes in the Gulf of Mexico and continuing restrictions in the capital markets, property damage and well control insurance coverage has become more limited and the cost of such coverage has increased. In June 2009, we renewed our insurance policies covering well control and hurricane damage at a cost of approximately $35 million. The current policy limits for well control and hurricane damage are $100 million and $85 million, respectively, with an additional $100 million for well control and hurricane damage on our Ship Shoal 349 field. A retention of $35 million per occurrence must be satisfied by us before we are indemnified for losses, and certain properties we have deemed as non-core are not covered for hurricane damage. However, properties representing approximately 89.3% of our PV-10 value at December 31, 2009 (before estimated asset retirement obligations) are covered under our new insurance policies for hurricane damage. Our insurers may not continue to offer this type and level of coverage to us, or our costs may increase substantially as a result of increased premiums and the increased risk of uninsured losses that may have been previously insured, all of which could have a material adverse effect on our financial condition and results of operations. We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have a claim, the insurance companies will not pay our claim. However, we are not aware of any financial issues related to any of our insurance underwriters that would affect their ability to pay claims. In April 2010, we renewed our general and excess liability insurance policies.

Capital expenditures. The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors, including the prices of oil and natural gas, anticipated operating cash flow, acquisition opportunities and the results of our exploration and development activities. For the three months ended March 31, 2010, our capital expenditures for oil and natural gas properties and equipment of $39.9 million included $19.4 million for exploration activities, $17.3 million for development activities and $3.2 million for seismic, capitalized interest and other leasehold costs. Our development and exploration capital expenditures consisted of $30.7 million on the conventional shelf and other projects, $4.3 million in the deepwater and $1.7 million on the deep shelf. Our capital expenditures for the three months ended March 31, 2010 were financed by net cash from operating activities and cash on hand.

Our total capital expenditure budget for 2010 is $450 million, comprised of both identified capital investment programs as described below and potential acquisitions, joint ventures and other drilling opportunities. We anticipate fully funding our 2010 capital budget with internally generated cash flow and cash on hand. The budget, as recently updated, includes nine exploration wells and one development well and other capital items such as well recompletions, facilities capital, seismic and leasehold items. At this time, we anticipate these capital expenditures will cost approximately $200 million. Another $125 million has been allocated to the purchase of certain properties as discussed below. The balance of the $450 million budget will be allocated to acquisitions, additional drilling opportunities from the company’s prospect inventory and/or new joint ventures offshore (on the shelf and in the deepwater) and onshore. Our 2010 capital budget is subject to change as conditions warrant.

On April 7, 2010, we entered into a PSA with Total to acquire all of Total’s interest, including production platforms and facilities, in three federal offshore lease blocks located in the Gulf of Mexico for a purchase price of $150 million, subject to customary closing adjustments, with an effective date of January 1, 2010. The transaction closed on April 30, 2010, with our wholly-owned subsidiary, Energy VI, as purchaser. The purchase price was adjusted for, among other things, net revenue and operating expenses from the effective date to the closing date and a down payment of $7.5 million, resulting in $117.5 million paid at closing. This acquisition was funded from cash on hand. In accordance with the PSA, Energy VI obtained unsecured surety bonds in favor of the MMS to secure the asset retirement obligations with respect to the Total assets. The PSA provides for annual increases in the required security for the asset retirement obligations. To satisfy the annual increases, Energy VI granted an overriding royalty from production of the acquired properties, payable to an escrow agent. As long as the required security amount then in effect is met, the payments under the overriding royalty will be promptly released to us by the escrow agent. We are currently in compliance with the required security amount.

The properties acquired from Total are producing interests with future development potential, and include a 100% working interest in Mississippi Canyon block 243 (“Matterhorn”) and a 64% working interest in Viosca Knoll blocks 822 and 823 (“Virgo”). The estimated proved oil and natural gas reserves on the effective date (determined using the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period) were 11.6 million Boe, or 69.7 Bcfe, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. The reserves acquired were estimated as 64% oil and 36% natural gas.

Long-term debt. At March 31, 2010, we had $0.7 million of letters of credit outstanding and we had $404.8 million of undrawn capacity under our revolving loan facility, which matures in 2012. Borrowings outstanding under our 8.25% Senior notes were $450.0 million at March 31, 2010, all of which are classified as long-term. In April 2010, we borrowed $142.5 million under our revolving loan facility. For additional details about our long-term debt, refer to Item 1 Financial Statements – Note 4 – Long-Term Debt.

Availability under the Credit Agreement is subject to a semi-annual borrowing base redetermination (March and September) set at the discretion of our lenders. The amount of the borrowing base is calculated by our lenders based on their valuation of our proved reserves and their own internal criteria. In April 2010, our borrowing base under the Credit Agreement was reaffirmed by our lenders at $405.5 million. Fifteen lenders participate in our revolving loan facility and we do not anticipate any of them being unable to satisfy their obligations under the Credit Agreement. We do not anticipate any immediate need for access to the capital markets. However, because of various factors, including our credit rating and our reserve and production profile, it could be difficult and/or expensive to obtain debt or equity capital funding at sufficient levels in the future.

The Credit Agreement contains various financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio and a maximum leverage ratio, as such ratios are defined in the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement as of March 31, 2010.

Dividends. During the three months ended March 31, 2010 and 2009, we paid regular cash dividends of $0.03 per common share. On May 3, 2010, our board of directors declared a cash dividend of $0.03 per common share, payable on June 23, 2010 to shareholders of record on May 26, 2010.

Contractual obligations. Except as described in “Cash flow and working capital,” “Capital expenditures” and “Long-term debt” above, information about contractual obligations for the quarter ended March 31, 2010, did not change materially from the disclosures in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2009.

Our significant accounting policies are summarized in Note 1 of Notes to Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2009. Also refer to the Notes to Condensed Consolidated Financial Statements included in Part 1, Item 1 of this Quarterly Report on Form 10-Q.

For a description of recent accounting pronouncements, see Item 1 Financial Statements – Note 2 – Recent Accounting Pronouncements.

Information about market risks for the quarter ended March 31, 2010, did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2009 except as noted below. As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the year ended December 31, 2009.

Commodity Price Risk. Our revenues, profitability and future rate of growth substantially depend upon market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility have adversely affected our revenues, net cash provided by operating activities and profitability. We have entered into a limited number of commodity option contracts and a commodity swap contract to help manage our exposure to commodity price risk from sales of oil and natural gas during the fiscal years ending December 31, 2010 and 2011. As of March 31, 2010, we had commodity derivative instruments relating to approximately 14 Bcfe of our anticipated production during the remainder of 2010 and approximately 7 Bcfe of our anticipated production in 2011. While these contracts are intended to reduce the effects of volatile oil and natural gas prices, they may also limit future income if oil and natural gas prices were to rise substantially over the price established by the hedge. We do not enter into derivative instruments for speculative trading purposes. For additional details about our commodity derivatives, refer to Item 1 Financial Statements – Note 6 – Derivative Financial Instruments.

Interest Rate Risk. We have an interest rate swap contract that serves to manage the risk associated with the floating rate of interest on our revolving loan facility. For additional details about our interest rate swap, refer to Item 1 Financial Statements – Note 6 – Derivative Financial Instruments.

We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC and that any material information relating to us is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have each concluded that as of March 31, 2010 our disclosure controls and procedures are effective to ensure that information we are required to disclose in 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, and that our controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

During the quarter ended March 31, 2010, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Carefully consider the risk factors set forth below, as well as the risk factors included under the caption “Risk Factors” under Part I, Item 1A in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, together with all of the other information included in this document, in the Company’s Annual Report on Form 10-K and in the Company’s other public filings, press releases and discussions with Company management.

Recent events in the Gulf of Mexico may result in drilling delays, increased governmental regulation of our operations and significantly more expensive insurance coverage for our assets.

On April 20, 2010, the Transocean Deepwater Horizon drilling rig experienced a fire and subsequently sank 130 miles south of New Orleans, Louisiana, and the resulting release of crude oil into the Gulf of Mexico has been declared a Spill of National Significance by the United States Department of Homeland Security. In response, members of the United States Congress have called for investigative hearings and a moratorium on President Obama’s plans to permit the expansion of offshore drilling activities. This event and its aftermath could serve as the impetus for additional governmental regulation of the offshore exploration and production industry, which may result in substantial increases in costs or delays in our drilling operations. We cannot predict with any certainty what form any additional regulation will take. Additionally, this accident may lead to further tightening of an increasingly difficult market for offshore property damage and well control insurance coverage. Insurers may not continue to offer the type and level of coverage which we currently maintain, and our costs may increase substantially as a result of increased premiums, potentially to the point where coverage is not available on economically manageable terms. If either additional governmental regulation is imposed or the insurance market becomes more restricted, it may increase the costs of conducting offshore exploration and development activities or result in significant delays, which could materially impact our business, financial condition and results of operations.

On May 3, 2010, the Compensation Committee of the Board of Directors (the “Compensation Committee”) of the Company approved a $500,000 bonus for 2009 for the Company’s Chairman and Chief Executive Officer. In accordance with the rules of the SEC, the table below updates Mr. Krohn’s 2009 compensation information to include the 2009 bonus information in the “2009 Summary Compensation Table,” which was originally included in the Company’s definitive proxy statement filed with the SEC on April 2, 2010 (the “Proxy Statement”). No other information has been revised. For additional information regarding Mr. Krohn’s compensation arrangements, please see the Proxy Statement.

The exhibits to this report are listed in the Exhibit Index appearing on page 22 hereof.

Pursuant to the requirements 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, on May 5, 2010.


W&T OFFSHORE, INC.

By:		/S/ JOHN D. GIBBONS
		John D. Gibbons
		Senior Vice President, Chief Financial Officer
		and Chief Accounting Officer, duly authorized
		to sign on behalf of the registrant


Texas		72-1121985
(State of incorporation)		(IRS Employer Identification Number)

Nine Greenway Plaza, Suite 300 Houston, Texas		77046-0908
(Address of principal executive offices)		(Zip Code)


		Page
PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009	1
	Condensed Consolidated Statements of Income (Loss) for the Three Months Ended March 31, 2010 and 2009	2
	Condensed Consolidated Statement of Changes in Shareholders’ Equity for the Three Months Ended March 31, 2010	3
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2010 and 2009	4
	Notes to Condensed Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	12

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	18

Item 4.	Controls and Procedures	19

PART II – OTHER INFORMATION

Item 1A.	Risk Factors	20

Item 5.	Other Information	20

Item 6.	Exhibits	20

SIGNATURE		21

EXHIBIT INDEX		22


	March 31, 2010			December 31, 2009
	(In thousands, except share data)
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	84,231		$	38,187
Receivables:
Oil and natural gas sales		43,588			54,978
Joint interest and other		26,045			51,312
Insurance		29,922			30,543
Income taxes		84,514			85,457

Total receivables		184,069			222,290
Prepaid expenses and other assets		27,441			28,777

Total current assets		295,741			289,254
Property and equipment – at cost:
Oil and natural gas properties and equipment (full cost method, of which $70,855 at March 31, 2010 and $77,301 at December 31, 2009 were excluded from amortization)		4,757,588			4,732,696
Furniture, fixtures and other		15,177			15,080

Total property and equipment		4,772,765			4,747,776
Less accumulated depreciation, depletion and amortization		3,815,904			3,752,980

Net property and equipment		956,861			994,796
Restricted deposits for asset retirement obligations		30,625			30,614
Deferred income taxes		—			5,117
Other assets		6,716			7,052

Total assets	$	1,289,943		$	1,326,833


Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	49,599		$	115,683
Undistributed oil and natural gas proceeds		22,083			32,216
Asset retirement obligations		107,632			117,421
Accrued liabilities		22,494			13,509
Deferred income taxes		1,873			5,117

Total current liabilities		203,681			283,946
Long-term debt		450,000			450,000
Asset retirement obligations, less current portion		231,322			231,379
Deferred income taxes		1,277			—
Other liabilities		3,672			2,558
Commitments and contingencies
Shareholders’ equity:
Common stock, $0.00001 par value; 118,330,000 shares authorized; 77,539,907 issued and 74,670,734 outstanding at March 31, 2010; 77,579,968 issued and 74,710,795 outstanding at December 31, 2009		1			1
Additional paid-in capital		374,015			373,050
Retained earnings		50,142			10,066
Treasury stock, at cost		(24,167	)		(24,167	)

Total shareholders’ equity		399,991			358,950

Total liabilities and shareholders’ equity	$	1,289,943		$	1,326,833


	Three Months Ended March 31,
	2010			2009
	(In thousands, except per share data)
	(Unaudited)

Revenues	$	169,585		$	117,422


Operating costs and expenses:
Lease operating expenses		35,366			50,230
Production taxes		229			710
Gathering and transportation		4,587			2,595
Depreciation, depletion and amortization		62,924			80,788
Asset retirement obligation accretion		6,285			10,747
Impairment of oil and natural gas properties		—			218,871
General and administrative expenses		10,379			11,436
Derivative (gain) loss		(5,896	)		392

Total costs and expenses		113,874			375,769

Operating income (loss)		55,711			(258,347	)
Interest expense:
Incurred		10,920			12,509
Capitalized		(1,416	)		(1,782	)
Other income		128			505

Income (loss) before income tax expense (benefit)		46,335			(268,569	)
Income tax expense (benefit)		4,020			(23,992	)

Net income (loss)	$	42,315		$	(244,577	)


Basic and diluted earnings (loss) per common share	$	0.57		$	(3.22	)
Dividends declared per common share	$	0.03		$	0.03

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company


	Common Stock				Additional Paid-In Capital		Retained Earnings			Treasury Stock				Total Shareholders’ Equity
	Shares		Value		Additional Paid-In Capital		Retained Earnings			Shares	Value			Total Shareholders’ Equity
	(In thousands)
	(Unaudited)
Balances at December 31, 2009	74,711		$	1	$	373,050	$	10,066		2,869	$	(24,167	)	$	358,950
Cash dividends	—			—		—		(2,239	)	—		—			(2,239	)
Share-based compensation	—			—		965		—		—		—			965
Restricted stock forfeited	(40	)		—		—		—		—		—			—
Net income	—			—		—		42,315		—		—			42,315

Balances at March 31, 2010	74,671		$	1	$	374,015	$	50,142		2,869	$	(24,167	)	$	399,991


Balance, December 31, 2009	$	348,800
Liabilities settled		(8,351	)
Accretion of discount		6,285
Disposition of properties		(1,520	)
Decrease in estimated liabilities associated with Hurricane Ike		(5,074	)
Decrease in estimated liabilities – all other		(1,186	)

Balance, March 31, 2010		338,954
Less current portion		107,632

Long-term	$	231,322


Zero Cost Collars – Oil
Effective Date	Termination Date	Notional Quantity (Bbls)	Weighted Average NYMEX Contract Price				Fair Value Liability (in thousands)
Effective Date	Termination Date	Notional Quantity (Bbls)	Floor		Ceiling		Fair Value Liability (in thousands)
4/1/2010	6/30/2010	692,950	$	72.12	$	86.34	$	(1,334	)
7/1/2010	9/30/2010	310,300		71.54		86.83		(981	)
10/1/2010	12/31/2010	420,650		71.95		89.07		(1,367	)
1/1/2011	3/31/2011	434,200		75.00		94.62		(501	)
4/1/2011	6/30/2011	382,100		75.00		94.60		(533	)
7/1/2011	9/30/2011	151,300		75.00		94.68		(233	)
10/1/2011	12/31/2011	244,900		75.00		96.08		(351	)

		2,636,400	$	73.35	$	90.78	$	(5,300	)


Zero Cost Collars – Natural Gas
	Termination Date	Notional Quantity (MMBtu)	Weighted Average NYMEX Contract Price				Fair Value Asset (in thousands)
Effective Date			Weighted Average NYMEX Contract Price
Effective Date			Floor		Ceiling
5/1/2010	6/30/2010	2,165,500	$	5.00	$	6.15	$	2,268
7/1/2010	9/30/2010	1,545,500		5.00		6.60		1,384
10/1/2010	12/31/2010	1,831,800		5.00		8.35		806

		5,542,800	$	5.00	$	7.00	$	4,458


Swap – Natural Gas
Effective Date	Termination Date	Notional Quantity (MMBtu)	Swap Price				Fair Value Asset (in thousands)
5/1/2010	12/31/2010	490,000		$5.71			$	581


Balance, December 31, 2009	$	30,543

Costs approved under our insurance policies:
Remediation		2,220
Plugging and abandonment		6,163

Payments received:
Remediation		(1,165	)
Plugging and abandonment		(7,839	)

Balance, March 31, 2010	$	29,922


	Restricted Shares		Weighted Average Grant Date Price Per Share
Nonvested at December 31, 2009	1,050,506		$	8.48
Granted	—			—
Forfeited	(40,061	)		8.46

Nonvested at March 31, 2010	1,010,445			8.48


	Restricted Shares
Employees – granted in:
2009	919,239	(1)
2008	53,049	(2)

Non-employee directors – granted in:
2009	32,320	(3)
2008	4,863	(4)
2007	974	(5)


Total	1,010,445


	Three Months Ended
	March 31,
	2010		2009
Net income (loss)	$	42,315	$	(244,577	)
Less portion allocated to nonvested shares		579		—

Net income (loss) allocated to common shares	$	41,736	$	(244,577	)


Weighted average common shares outstanding		73,660		75,980


Basic earnings (loss) per common share	$	0.57	$	(3.22	)


	Three Months Ended March 31,
	2010			2009 (2)			Change			%
	(In thousands, except per share data)
Financial:
Revenues:
Oil	$	115,480		$	53,595		$	61,885		115.5	%
Natural gas		54,070			63,821			(9,751	)	(15.3	)%
Other		35			6			29		483.3	%

Total revenues		169,585			117,422			52,163		44.4	%
Operating costs and expenses:
Lease operating expenses (1)		35,366			50,230			(14,864	)	(29.6	)%
Production taxes		229			710			(481	)	(67.7	)%
Gathering and transportation		4,587			2,595			1,992		76.8	%
Depreciation, depletion, amortization and accretion		69,209			91,535			(22,326	)	(24.4	)%
Impairment of oil and natural gas properties (2)		—			218,871			(218,871	)	(100.0	)%
General and administrative expenses		10,379			11,436			(1,057	)	(9.2	)%
Derivative (gain) loss (3)		(5,896	)		392			(6,288	)	NM

Total costs and expenses		113,874			375,769			(261,895	)	(69.7	)%

Operating income (loss)		55,711			(258,347	)		314,058		121.6	%
Interest expense, net of amounts capitalized		9,504			10,727			(1,223	)	(11.4	)%
Other income		128			505			(377	)	(74.7	)%

Income (loss) before income tax expense (benefit)		46,335			(268,569	)		314,904		117.3	%
Income tax expense (benefit)		4,020			(23,992	)		28,012		116.8	%

Net income (loss)	$	42,315		$	(244,577	)	$	286,892		117.3	%

Basic and diluted earnings (loss) per common share	$	0.57		$	(3.22	)	$	3.79		117.7	%

	Three Months Ended March 31,
	2010			2009			Change			%
Operating:
Net sales:
Natural gas (Bcf)		10.0			12.6			(2.6	)	(20.6	)%
Oil (MMBbls)		1.7			1.5			0.2		13.3	%
Total natural gas and oil (Bcfe) (4)		20.0			21.4			(1.4	)	(6.5	)%
Average daily equivalent sales (MMcfe/d)		221.7			237.9			(16.2	)	(6.8	)%
Average realized sales prices (Unhedged):
Natural gas ($/Mcf)	$	5.38		$	5.08		$	0.30		5.9	%
Oil ($/Bbl)		69.95			36.29			33.66		92.8	%
Natural gas equivalent ($/Mcfe)		8.50			5.48			3.02		55.1	%
Average realized sales prices (Hedged):
Natural gas ($/Mcf)	$	5.57		$	5.08		$	0.49		9.6	%
Oil ($/Bbl)		69.46			36.29			33.17		91.4	%
Natural gas equivalent ($/Mcfe)		8.55			5.48			3.07		56.0	%
Average per Mcfe ($/Mcfe):
Lease operating expenses (1)	$	1.77		$	2.35		$	(0.58	)	(24.7	)%
Gathering and transportation		0.23			0.12			0.11		91.7	%

Production costs		2.00			2.47			(0.47	)	(19.0	)%
Production taxes		0.01			0.03			(0.02	)	(66.7	)%
Depreciation, depletion, amortization and accretion		3.47			4.27			(0.80	)	(18.7	)%
General and administrative expenses		0.52			0.53			(0.01	)	(1.9	)%

	$	6.00		$	7.30		$	(1.30	)	(17.8	)%

Total number of wells drilled (gross)		3			4			(1	)	(25.0	)%
Total number of productive wells drilled (gross)		2			3			(1	)	(33.3	)%


Name and Principal Position	Year	Salary		Cash Bonus(3)		Stock Awards(4)		Non-Equity Incentive Plan Compensation(5)		All Other Compensation(6)(7)		Total
Tracy W. Krohn	2009	$	1,038,462	$	500,000	$	—	$	—	$	424,546	$	1,963,008
Chairman and Chief Executive	2008		594,703		500,000		—		—		391,472		1,486,175
Officer	2007		500,000		—		—		—		418,552		918,552


Exhibit Number		Description
31.1*		Section 302 Certification of Chief Executive Officer.

31.2*		Section 302 Certification of Chief Financial Officer.

32.1*		Section 906 Certification of Chief Executive Officer and Chief Financial Officer.