Form 10-Q for quarterly period ended June 30, 2009

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.

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨

As of August 4, 2009, there were 76,386,861 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. 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, 2008.

Reclassifications. 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.

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.

Earnings (Loss) Per Share. Effective January 1, 2009, the Company adopted Financial Accounting Standards Board (“FASB”) Staff Position (“FSP”) No. Emerging Issues Task Force (“EITF”) 03-6-1 (“FSP 03-6-1”), Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. This FSP provides 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 described in Statement of Financial Accounting Standards (“SFAS”) No. 128, Earnings Per Share. For additional information about the impact of the adoption of FSP 03-6-1 on our financial statements, refer to Note 12.

Subsequent Events. The accompanying unaudited condensed consolidated financial statements reflect management’s evaluation of subsequent events through the time of filing on August 4, 2009, the date of issuance of the financial statements.

In May 2009, the FASB issued SFAS No. 165, Subsequent Events, to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before the financial statements are issued (“subsequent events”). SFAS No. 165 defines two types of subsequent events as “recognized” and “nonrecognized.” Recognized subsequent events are events that provide additional evidence about conditions that existed at the balance sheet date (including estimates inherent in the process of preparing the financial statements) and therefore should be recorded in the financial statements. Nonrecognized subsequent events are events that do not provide evidence about conditions that existed at the balance sheet date but are considered to be material and therefore should be disclosed. The new standard requires disclosure of the date through which management has evaluated subsequent events and the basis for such date, which for public entities is generally the date the financial statements are issued. SFAS No. 165 is effective for interim or annual reporting periods ending after June 15, 2009, and shall be applied prospectively. SFAS No. 165 is not applicable to specific subsequent events that fall within the scope of other GAAP. The adoption of SFAS No. 165 did not have an impact on the Company’s financial position, cash flows or results of operations.

In April 2009, the FASB issued FSP No. FAS 107-1 and APB 28-1 (“FSP 107-1”), Interim Disclosures about Fair Value of Financial Instruments. FSP 107-1 requires public companies to include disclosures about the fair value of their financial instruments in interim reporting periods, as well as the methods, significant assumptions and any changes in such methods and assumptions used to estimate the fair value of financial instruments. FSP 107-1 is effective for interim reporting periods ending after June 15, 2009. The adoption of FSP 107-1 did not have a material impact on the Company’s financial statements.

Effective January 1, 2009, the Company adopted SFAS No. 141 (revised 2007) (“SFAS No. 141(R)”), Business Combinations. SFAS No. 141(R) requires the acquiring entity in a business combination to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree to be measured at their respective fair values at the acquisition date. It also requires the acquirer to record the fair value of contingent consideration (if any) at the acquisition date. Acquisition-related costs incurred prior to the acquisition are required to be expensed rather than included in the purchase-price determination. SFAS No. 141(R) also provides guidance for recognizing and measuring the goodwill acquired in a business combination and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The statement applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. We expect SFAS No. 141(R) will have an impact on our consolidated financial statements, but the nature and magnitude of the specific effects will depend upon the nature, terms and size of acquisitions, if any, that we may consummate in the future.

Effective January 1, 2009, the Company adopted SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51. SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. The adoption of SFAS No. 160 did not have a material impact on the Company’s financial statements.

On December 29, 2008, the SEC adopted new rules related to modernizing accounting and disclosure requirements for oil and natural gas companies. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The new rules also allow companies the option to disclose probable and possible reserves in addition to the existing requirement to disclose proved reserves. The new disclosure requirements also require companies to report the independence and qualifications of third party preparers of reserves and file reports when a third party is relied upon to prepare reserves estimates. A significant change to the rules involves the pricing at which reserves are measured. The new rules utilize a 12-month average price using beginning of the month pricing (January 1 to December 1) to report oil and natural gas reserves rather than year-end prices. In addition, the 12-month average will be used to calculate the cost center ceilings for impairment and to compute depreciation, depletion and amortization. The new rules are effective January 1, 2010 with first reporting for calendar year companies in their 2009 annual reports. Early adoption is not permitted. The Company has not completed its evaluation of the impact of the new rules on its financial statements.

Under the full cost method of accounting, we are required to periodically perform a “ceiling test,” which determines a limit on the book value of our oil and natural gas properties. If the net capitalized cost of oil and natural gas properties (including capitalized asset retirement obligations), net of related deferred income taxes,

exceeds the present value of estimated future net revenues from proved oil and natural gas reserves discounted at 10%, net of related tax effects, plus the cost of unproved oil and natural gas properties, the excess is charged to expense and reflected as additional accumulated depreciation, depletion and amortization. Any such write-downs are not recoverable or reversible in future periods. Estimated future net revenues are based on period-end commodity prices and exclude future cash outflows related to capitalized asset retirement obligations and include future development costs and asset retirement obligations related to wells to be drilled. Primarily as a result of a decline in natural gas prices as of March 31, 2009, we recorded a ceiling test impairment at March 31, 2009 of $205.0 million. We did not have a ceiling test impairment during the three months ended June 30, 2009 or the three and six months ended June 30, 2008. Further declines in oil and natural gas prices after June 30, 2009 may require us to record additional ceiling test impairments in the future.

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. Effective January 1, 2009, our asset retirement obligations incurred are initially measured at fair value in accordance with SFAS No. 157. A summary of our asset retirement obligations is as follows (in thousands):

In connection with the sale of certain assets during the second quarter of 2009, we reduced our asset retirement obligations by $75.2 million. Additionally, during the six months ended June 30, 2009, we increased our asset retirement obligations by $41.7 million, the majority of which relates to bids received from external third parties and revised estimates for the dismantlement of two operated platforms that were toppled during Hurricane Ike and the plugging and abandonment of the associated wells. Included in liabilities settled for the six months ended June 30, 2009 is $12.8 million to plug and abandon wells and facilities as a result of damage caused by Hurricane Ike. See Note 9 for additional details about the impact of Hurricane Ike on our financial statements.

In March 2009, we announced by press release a $25 million stock repurchase program. Under the program, shares may be purchased from time to time at prevailing prices in the open market, in block transactions, in privately negotiated transactions or accelerated share repurchase programs through December 31, 2009, in accordance with Rule 10b-18 under the Securities Exchange Act of 1934 (the “Exchange Act”). The timing and actual number of shares purchased will depend on a variety of factors, such as the price of our common stock, corporate and regulatory requirements, alternative investment opportunities and other market and economic conditions. The repurchase program does not obligate us to acquire any specific number of shares and may be discontinued at any time. Repurchases will be funded with cash on hand. During the six months ended June 30, 2009, we purchased 1,429,486 shares of our common stock for approximately $9.2 million in the open market in accordance with the repurchase program.

As of June 30, 2009 and December 31, 2008, our long-term debt was as follows (in thousands):

Borrowings under the Third Amended and Restated Credit Agreement, as amended (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 2009, our lenders reduced the borrowing base from $710.0 million to $405.5 million. In May 2009, the Company paid in full the Tranche B term loan facility outstanding balance of $204.75 million plus accrued and unpaid interest of $0.7 million with borrowings under the revolving loan facility. In June 2009, we repaid $62.9 million under the revolving loan facility. During the quarter ended June 30, 2009, we recorded a loss of $2.9 million related to the write-off of all the deferred financing costs related to the Tranche B term loan facility and the write-off of a portion of the deferred financing costs related to the revolving loan facility, as well as the incurrence of other incidental costs in connection with the payoff of the Tranche B term loan facility. At June 30, 2009, we had $0.6 million of letters of credit outstanding and our remaining availability under the revolving loan facility was $262.4 million.

Effective May 4, 2009, borrowings under the revolving loan facility bear interest at either (1) the highest of the Prime Rate, the Federal Funds Rate plus 0.50%, or the one-month Eurodollar Rate plus 1.0%, plus a margin which varies from 0.75% to 1.75% depending on the level of total borrowings under the Credit Agreement, or (2) to the extent the loan outstanding is designated as a Eurodollar loan, at the London Interbank Offered Rate (“LIBOR”) plus a margin that varies from 2.0% to 3.0% depending on the level of total borrowings under the Credit Agreement. The Credit Agreement also bears an unused commitment fee of 0.50%. The estimated effective interest rate on the revolving loan facility, including unused commitment fees and amortization of deferred financing costs, was 6.5% during the six months ended June 30, 2009.

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, a minimum asset coverage ratio and a maximum leverage ratio, as such ratios are defined in the Credit Agreement. In connection with the April 2009 borrowing base redetermination, we amended the maximum leverage ratio, which is the ratio of total debt to EBITDA (as those terms are defined in the Credit Agreement), to be 3.75 to 1 for the four quarters ended September 30, 2009, 3.50 to 1 for the four quarters ended December 31, 2009, 3.25 to 1 for the four quarters ended March 31, 2010 and 3.00 to 1 thereafter. We were in compliance with all applicable covenants of the Credit Agreement as of June 30, 2009.

The 8.25% Senior notes (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 June 30, 2009, the estimated fair value of the Notes was approximately $340 million, based on quoted prices. The estimated annual effective interest rate on the Notes is 8.4%.

Effective January 1, 2009, the Company adopted SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133. SFAS No. 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments; (b) how derivative instruments and related hedged items are accounted for under SFAS No. 133, as amended; and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 did not have an impact on the Company’s financial position, results of operations or cash flows upon adoption.

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; however, we did not have any open commodity derivatives at any time during 2009 and we do not enter into derivative instruments for speculative trading purposes. Currently, we are party to one interest rate swap contract with a financial institution. The Company is exposed to credit loss in the event of nonperformance by the counterparty; however, we do not anticipate such counterparty nonperformance.

We account for derivative contracts in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. SFAS No. 133 requires each derivative to be recorded on the balance sheet as an asset or a liability at its fair value. Additionally, the statement requires that changes in a derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met at the time the derivative contract is entered into.

Interest Rate Swap. Our interest rate swap contract served to hedge the risk associated with the variable LIBOR used to reset the floating rate of our Tranche B term loan facility. In May 2009, we repaid the Tranche B term loan facility in full with borrowings under the revolving loan facility. Because interest on borrowings under the revolving loan facility is also calculated based on a floating rate of interest (see Note 6), we elected to retain our interest rate swap. We pay the counterparty the equivalent of a fixed interest payment and receive from the counterparty the equivalent of a floating interest payment based on a 3-month LIBOR. All interest rate swap payments are made quarterly and the LIBOR is determined in advance of each interest period. The fixed interest rate of the swap is 5.21%. As of June 30, 2009, the total notional amount of the swap was $147.0 million.

Changes in the fair value of our interest rate swap are recognized currently in earnings. During the three and six months ended June 30, 2009, we recorded realized losses of $1.5 million and $2.9 million, respectively, offset by changes in fair value of $1.0 million and $2.0 million, respectively, in earnings. During the three and six months ended June 30, 2008, we recorded realized losses of $1.0 million and $1.1 million, respectively, offset by changes in fair value of $4.2 million and $0.3 million, respectively, in earnings related to our interest rate swap.

At June 30, 2009, the fair value of our interest rate swap was $7.0 million, of which $6.3 million was included in accrued liabilities and $0.7 million was included in other liabilities, representing the current and non-current portions, respectively. We measure the fair value of our interest rate swap by applying the income approach, and our swap is classified within level 2 of the valuation hierarchy set forth in SFAS No. 157, Fair Value Measurements. The amount in accumulated other comprehensive loss of approximately $0.3 million (net of tax) at June 30, 2009 is related entirely to our interest rate swap and will be recognized in earnings over the remaining term of the swap, which expires in August 2010.

Commodity Derivatives. As of June 30, 2009 and December 31, 2008, we did not have any open commodity derivative positions. Our derivative loss for the three months ended June 30, 2008 includes a realized loss of $12.6 million related to our commodity derivative contracts and a change in the fair value of our commodity derivative contracts of $14.4 million. Our derivative loss for the six months ended June 30, 2008 includes a realized loss of $18.6 million related to our commodity derivative contracts and a change in the fair value of our commodity derivative contracts of $16.7 million.

At June 30, 2009, we had a federal income tax receivable of $50.9 million, which consisted of carrybacks to 2007 of net operating losses generated in 2009 and 2008. During the quarter ended March 31, 2009, we received a refund of $17.7 million, consisting of a reimbursement of federal tax payments that were deposited in 2008. An income tax benefit of $10.5 million and $34.5 million was recorded during the three and six months ended June 30, 2009, respectively, compared to income tax expense of $70.5 million and $111.9 million for the same periods of 2008. The income tax benefit for the six months ended June 30, 2009 resulted from a pre-tax loss of $271.2 million, only a portion of which is expected to be available to be carried back to 2007, which is the only open tax year that is currently available. Our effective tax rate for the quarter ended June 30, 2009 was approximately 63.8% and primarily reflects adjustments to our forecasted annual tax rate. Our effective tax rate for the six months ended June 30, 2009 was approximately 12.7% and primarily reflects the effect of a valuation allowance against our deferred tax assets. Our effective tax rate for the three and six months ended June 30, 2008 was approximately 34% and reflected the anticipated utilization of the deduction attributable to qualified domestic production activities under Section 199 of the Internal Revenue Code.

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. The policy limits 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.

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

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. We also recorded $2.1 million of insurance receivables at December 31, 2008 associated with hurricane-related lease operating expenses. During the six months ended June 30, 2009, we received proceeds of $5.2 million in connection with one of our non-operated properties that was deemed a total loss.

Included in lease operating expenses for the three and six months ended June 30, 2009 are hurricane remediation costs of $5.0 million and $15.2 million, respectively, which are comprised of $10.4 million and $28.9 million of remediation costs incurred less $5.4 million and $13.7 million of amounts approved under our insurance policies for the respective periods. At June 30, 2009, $5.4 million for recovery of remediation costs is included in insurance receivables.

Since the third quarter of 2008, we have spent $19.3 million to plug and abandon wells and facilities as a result of damage caused by Hurricane Ike. In addition, at June 30, 2009, we recorded a $44.2 million liability related to incremental costs of plugging and abandonment of wells in connection with two platforms toppled by Hurricane Ike, which are scheduled to be completed within the next year (see Note 4). 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, and has indicated that our insurance policies provide coverage for such costs and they are within policy limits, we have recognized an insurance receivable. Included in insurance receivables at June 30, 2009 is $50.2 million related to the dismantlement and plugging and abandonment of wells and facilities damaged as a result of Hurricane Ike.

We expect that our available cash and cash equivalents, cash flow from operations and the availability under our credit facility will be more than sufficient to meet any necessary expenditures that may exceed our insurance coverage for damages incurred as a result of Hurricanes Ike and Gustav.

In February 2009, the Compensation Committee and the Board of Directors approved payment of a general bonus of approximately $17.9 million for 2008 in accordance with the 2005 Annual Incentive Plan and the Long-Term Incentive Compensation Plan (together, the “Bonus Plan”), consisting of cash and restricted stock.

Cash bonuses for 2008 were paid in March 2009 and totaled $7.4 million. Of this amount, $5.4 million was expensed in 2008, $1.7 million was expensed in 2009 and the remainder was billed to partners under joint operating agreements.

In March 2009, the Compensation Committee of the Board of Directors approved a modification to the restricted stock portion of the 2008 bonus. Due to a decline in the market price of the Company’s common stock, the Compensation Committee determined that the number of shares available for issuance under the Bonus Plan was insufficient to cover 100% of the restricted stock portion of the 2008 bonus. Accordingly, in March 2009, the Company granted to its employees, on a pro-rata basis, substantially all of the shares of restricted stock available to be issued under the Bonus Plan, representing 1,124,603 restricted shares of our common stock with a fair value on the dates of grant of approximately $6.0 million. In May 2009, the Company’s shareholders approved an increase in the number of shares available for issuance under the Bonus Plan of 2,000,000 shares. Also in May 2009, the Company granted to its employees 413,513 shares of restricted stock with a fair value on the date of grant of approximately $4.5 million to satisfy the remainder of the 2008 bonus.

The compensation expense associated with the restricted stock portion of the 2008 Bonus, less an allowance for estimated forfeitures, is being recognized over the requisite service period of four years beginning on January 1, 2008. Accrued liability amounts of approximately $2.9 million ($2.3 million at December 31, 2008) related to the recognition of compensation expense during the service period prior to the issuance of the restricted shares were reclassified to additional paid-in capital during the six months ended June 30, 2009 (see Note 11). Pursuant to the terms of the Bonus Plan, we have not met any of the prerequisites and therefore have not accrued any amounts for a 2009 bonus.

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 six months ended June 30, 2009, is as follows:

At June 30, 2009, there were 1,622,785 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 six months ended June 30, 2009, a total of 1,538,116 restricted shares of our common stock were granted to employees pursuant to our share-based payment plans. With certain exceptions, these shares will vest in three equal installments with the first such installment vesting in December 2009, and the remainder, less any forfeited shares, vesting in December 2010 and 2011. During the six months ended June 30, 2009, 26,185 restricted shares held by two former employees were vested early pursuant to the terms of the Bonus Plan.

Also during the six months ended June 30, 2009, our non-employee directors were granted a total of 32,320 restricted shares of our common stock. With certain exceptions, shares granted to our non-employee directors vest in three equal installments on the first, second and third anniversaries from the date of grant. During the six months ended June 30, 2009, 4,310 restricted shares held by our non-employee directors vested.

The weighted average grant date fair value of restricted shares granted during the six months ended June 30, 2009 and 2008 was $10.9 million and $6.6 million, respectively. The weighted average fair value of the shares that vested during the six months ended June 30, 2009 and 2008 was $0.3 million and $0.6 million, respectively, based on the closing prices on the dates of vesting.

During the three months ended June 30, 2009 and 2008, total compensation expense under share-based payment arrangements was $2.6 million and $2.0 million, respectively. During each of the six month periods ended June 30, 2009 and 2008, total compensation expense under share-based payment arrangements was $4.2 million. As of June 30, 2009, there was $10.2 million of total unrecognized share-based compensation expense related to restricted shares issued. Such amount is expected to be recognized in the period beginning July 2009 and ending April 2012.

Effective January 1, 2009, the Company adopted FSP 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. This FSP provides 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 described in SFAS No. 128, Earnings Per Share.

The following table presents the calculation of basic earnings (loss) per common share for the three and six months ended June 30, 2009 and 2008 (in thousands, except per share amounts):

Earnings per share data for the three and six months ended June 30, 2008 has been calculated and restated retrospectively in accordance with FSP 03-6-1, which resulted in a decrease of $0.01 from each of the amounts previously reported as basic and diluted earnings per common share for the three and six months ended June 30, 2008. The

adoption of FSP 03-6-1 did not have an effect on our basic and diluted loss per common share for the three and six months ended June 30, 2009. Basic and diluted earnings (loss) per common share are the same because the nonvested shares outstanding during the periods are anti-dilutive.

Our comprehensive income (loss) for the periods indicated is as follows (in thousands):

During the six months ended June 30, 2009, we paid regular cash dividends of $0.06 per common share. During the six months ended June 30, 2008, we paid regular cash dividends of $0.06 per common share and a special cash dividend of $30.0 million, or approximately $0.39 per common share. On August 3, 2009, our board of directors declared a cash dividend of $0.03 per common share, payable on September 17, 2009 to shareholders of record on August 20, 2009.

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. Some of these claims relate to matters occurring prior to our acquisition of properties and some relate to properties we have sold. In certain cases, we are entitled to indemnification from the sellers of properties and in other cases, we have indemnified the buyers to whom we have sold properties. Although we can give no assurance about the outcome of pending legal and 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.

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, 2008 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 148 producing fields in federal and state waters. The majority of our daily production is derived from wells we operate.

Our business and operations continue to be significantly affected by reductions in oil and natural gas prices over the past year. While oil prices have shown some signs of recovery since the end of 2008, they have continued to be significantly below the peak levels they reached in July 2008. The price of oil was approximately $70 per barrel at the end of June 2009, representing an increase of 71% from approximately $41 per barrel at the end of 2008. Natural gas prices have continued to weaken. The price of natural gas was approximately $3.84 per Mcf at the end of June 2009, representing a decrease of 33% from approximately $5.70 per Mcf at the end of 2008. During the six months ended June 30, 2009, our average realized prices on sales of our oil and natural gas were $44.93 per barrel and $4.47 per Mcf, respectively. Although our average realized sales prices for oil and natural gas were relatively weak during the first six months of 2009, the costs of goods and services that we consume in our normal operations remained proportionately high during the same time period as a result of commitments in 2008, which dramatically reduced our cash flows. Continued lower prices will negatively impact our future oil and natural gas revenues, earnings and liquidity. Further declines in oil and natural gas prices after June 30, 2009 could result in additional ceiling test impairments of the carrying value of our oil and natural gas properties and a reduction of the borrowing base on our credit agreement. Such declines 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 June 30, 2009 Compared to the Three Months Ended June 30, 2008

Revenues. Revenues decreased $310.6 million to $150.4 million for the three months ended June 30, 2009 as compared to the same period in 2008. Oil revenues decreased $166.5 million, natural gas revenues decreased $144.0 million and other revenues decreased $0.1 million. The oil revenue decrease was primarily attributable to a 54.6% decrease in the average realized oil price to $51.61 per barrel for the three months ended June 30, 2009 from $113.74 per barrel for the same period in 2008, as well as a 17.4% decrease in sales volumes. The natural gas revenue decrease resulted from a 66.3% decrease in the average realized natural gas price to $3.89 per Mcf in the 2009 period from $11.53 per Mcf in the 2008 period, as well as a 21.8% decrease in sales volumes. The sales volume decreases for oil and natural gas are primarily attributable to the deferral of production caused by Hurricanes Gustav and Ike in 2008 and natural reservoir declines. During the second quarter of 2009, production of approximately 24 MMcfe per day remained shut-in due to hurricane damage. Prior to Hurricane Gustav, our production was averaging approximately 324 MMcfe per day. After the hurricanes, we were almost completely shut-in for approximately one month, and when production resumed, we were producing approximately 72 MMcfe per day. Since then, production has increased as a result of our restoration efforts and the return to service of third-party pipelines and processing facilities upon which we depend to transport our production to the marketplace. During the fourth quarter of 2008 our average daily production was approximately 176 MMcfe per day, and during June 2009 our average daily production was approximately 272 MMcfe per day. Production of approximately 21 MMcfe per day is currently shut-in due to hurricane damage and we expect the majority of this production will be reestablished by the fourth quarter of 2009.

Lease operating expenses. Lease operating expenses, which includes base lease operating expenses, insurance costs, workovers and maintenance on our facilities, increased to $2.18 per Mcfe in the second quarter of 2009 from $1.75 per Mcfe in the second quarter of 2008. Lower production volumes during the 2009 period accounted for all of the increase in lease operating expenses per Mcfe. On a nominal basis, lease operating expenses decreased $0.2 million to $54.1 million in the second quarter of 2009, compared to the second quarter of 2008. Included in lease operating expenses for the 2009 period are $5.0 million of hurricane remediation costs related to Hurricanes Ike and Gustav that were either not yet approved by our insurance underwriters’ adjuster or were not covered by insurance. Lease operating expenses will be offset in future periods to the extent that these costs are recovered under our insurance policies. Offsetting the hurricane remediation costs in 2009 were decreases in base lease operating expenses of $1.6 million, insurance costs of $0.7 million, workovers of $1.0 million and facility expenditures of $1.9 million. The decrease in base lease operating expenses primarily reflects lower overall service and supply costs in 2009.

Production taxes. Production taxes decreased to $0.6 million for the three months ended June 30, 2009 from $3.2 million for the same period in 2008 primarily due to lower production from fields in state waters of Texas and Louisiana and lower realized prices on sales of our oil and natural gas. Most of our production is from federal waters where there are no production taxes.

Gathering and transportation costs. Gathering and transportation costs decreased to $3.8 million for the three months ended June 30, 2009 from $4.8 million for the same period in 2008 primarily due to lower production volumes of oil and natural gas.

Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion (“DD&A”) decreased to $84.6 million for the quarter ended June 30, 2009 from $153.8 million for the same period in 2008. DD&A decreased due to lower volumes of oil and natural gas produced and a lower depreciable base (resulting from ceiling test impairments of $1.2 billion and $205.0 million recognized in 2008 and the first quarter of

2009, respectively, and a reduction of our asset retirement obligations of $75.2 million from the sale of certain assets), partially offset by lower oil and natural gas reserves, compared to 2008. On a per Mcfe basis, DD&A was $3.41 for the quarter ended June 30, 2009, compared to $4.97 for the quarter ended June 30, 2008.

General and administrative expenses. General and administrative expenses (“G&A”) decreased to $10.7 million for the three months ended June 30, 2009 from $11.1 million for the same period in 2008, primarily due to lower incentive compensation and travel expenses, partially offset by higher fees for professional and contract services and reduced overhead credits billed to joint operators. On a per Mcfe basis, G&A was 0.43 per Mcfe for the three months ended June 30, 2009, compared to 0.36 per Mcfe for the same period in 2008.

Derivative loss. For the quarter ended June 30, 2009, our derivative loss of $0.5 million consisted of a realized loss of $1.5 million related to our interest rate swap offset by a change in the fair value of our interest rate swap of $1.0 million. For the quarter ended June 30, 2008, our derivative loss of $23.8 million consisted of a realized loss of $12.6 million related to our commodity derivative contracts and a change in the fair value of our commodity derivative contracts of $14.4 million. Also included in the 2008 period is a realized loss of $1.0 million related to our interest rate swap offset by a change in the fair value of our interest rate swap of $4.2 million. For additional details about our derivatives, refer to Item 1 Financial Statements – Note 7 – Derivative Financial Instruments.

Interest expense. Interest expense incurred decreased to $11.7 million for the quarter ended June 30, 2009 from $12.5 million for the quarter ended June 30, 2008 primarily due to lower interest rates and lower debt outstanding during the 2009 period. During the 2009 and 2008 periods, $1.7 million and $4.8 million, respectively, of interest expense was capitalized to unevaluated oil and natural gas properties.

Loss on extinguishment of debt. In May 2009, we repaid the Tranche B term loan facility in full with borrowings under our revolving loan facility. During the quarter ended June 30, 2009, we recorded a loss of $2.9 million related to the write-off of all the deferred financing costs related to the Tranche B term loan facility and the write-off of a portion of the deferred financing costs related to the revolving loan facility, as well as the incurrence of other incidental costs in connection with the payoff of the Tranche B term loan facility.

Other income. Other income, consisting of interest income, decreased to $0.2 million for the quarter ended June 30, 2009 from $2.7 million for the same period in 2008 due to lower average daily cash balances and a reduction in market interest rates received on invested cash.

Income tax expense/benefit. An income tax benefit of $10.5 million was recorded during the three months ended June 30, 2009, compared to income tax expense of $70.5 million for the same period in 2008. The income tax benefit in 2009 resulted from a pre-tax loss of $16.5 million, only a portion of which is expected to be available to be carried back to 2007, which is the only open tax year that is currently available. Our effective tax rate for the quarter ended June 30, 2009 was approximately 63.8% and primarily reflects adjustments to our forecasted annual tax rate. Our effective tax rate for the three months ended June 30, 2008 was approximately 34% and reflected the anticipated utilization of the deduction attributable to qualified domestic production activities under Section 199 of the Internal Revenue Code.

Six Months Ended June 30, 2009 Compared to the Six Months Ended June 30, 2008

Revenues. Revenues decreased $549.6 million to $267.9 million for the six months ended June 30, 2009 as compared to the same period in 2008. Oil revenues decreased $315.5 million, natural gas revenues decreased $234.0 million and other revenues decreased $0.1 million. The oil revenue decrease was primarily attributable to a 56.6% decrease in the average realized oil price to $44.93 per barrel for the six months ended June 30, 2009 from $103.46 per barrel for the same period in 2008, as well as a 24.4% decrease in sales volumes. The natural gas revenue decrease resulted from a 55.7% decrease in the average realized natural gas price to $4.47 per Mcf in the 2009 period from $10.09 per Mcf in the 2008 period, as well as a 25.4% decrease in sales volumes. The sales volume decreases for oil and natural gas are primarily attributable to the deferral of production caused by Hurricanes Gustav and Ike in 2008 and natural reservoir declines. During the first six months of 2009, production of approximately 46 MMcfe per day remained shut-in due to hurricane damage. Production of approximately 21 MMcfe per day is currently shut-in due to hurricane damage and we expect the majority of this production will be reestablished by the fourth quarter of 2009.

Lease operating expenses. Lease operating expenses increased to $2.26 per Mcfe for the six months ended June 30, 2009 from $1.69 per Mcfe in the same period in 2008. Lower production volumes during the 2009 period accounted for substantially all of the increase in lease operating expenses per Mcfe. On a nominal basis, lease operating expenses increased $0.2 million to $104.3 million during the six months ended June 30, 2009, compared to the same period in 2008. Included in lease operating expenses for the 2009 period are $15.2 million of hurricane remediation costs related to Hurricanes Ike and Gustav that were either not yet approved by our insurance underwriters’ adjuster or were not covered by insurance. Lease operating expenses will be offset in future periods to the extent that these costs are recovered under our insurance policies. Offsetting the hurricane remediation costs in 2009 were decreases in base lease operating expenses of $7.2 million, insurance costs of $2.0 million, workovers of $3.3 million and facility expenditures of $2.5 million. The decrease in base lease operating expenses primarily reflects lower overall service and supply costs in 2009.

Production taxes. Production taxes decreased to $1.3 million for the six months ended June 30, 2009 from $5.4 million for the same period in 2008 primarily due to lower production from fields in state waters of Texas and Louisiana and lower realized prices on sales of our oil and natural gas. Most of our production is from federal waters where there are no production taxes.

Gathering and transportation costs. Gathering and transportation costs decreased to $6.4 million for the six months ended June 30, 2009 from $11.4 million for the same period in 2008 primarily due to lower production volumes of oil and natural gas.

Depreciation, depletion, amortization and accretion. DD&A decreased to $176.1 million for the six months ended June 30, 2009 from $299.3 million for the same period in 2008. DD&A decreased due to lower volumes of oil and natural gas produced and a lower depreciable base (resulting from ceiling test impairments of $1.2 billion and $205.0 million recognized in 2008 and the first quarter of 2009, respectively, and a reduction of our asset retirement obligations of $75.2 million from the sale of certain assets), partially offset by lower oil and natural gas reserves, compared to 2008. On a per Mcfe basis, DD&A was $3.81 for the six months ended June 30, 2009, compared to $4.85 for the same period in 2008.

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 $205.0 million 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. We did not have a ceiling test impairment during the six months ended June 30, 2008.

General and administrative expenses. G&A decreased to $22.2 million for the six months ended June 30, 2009 from $23.6 million for the same period in 2008, primarily due to lower incentive compensation and travel expenses, partially offset by higher salaries, fees for professional and contract services and reduced overhead credits billed to joint operators. On a per Mcfe basis, G&A was 0.48 per Mcfe for the six months ended June 30, 2009, compared to 0.38 per Mcfe for the same period in 2008.

Derivative loss. For the six months ended June 30, 2009, our derivative loss of $0.9 million consisted of a realized loss of $2.9 million related to our interest rate swap offset by a change in the fair value of our interest rate swap of $2.0 million. For the six months ended June 30, 2008, our derivative loss of $36.1 million consisted of a realized loss of $18.6 million related to our commodity derivative contracts and a change in the fair value of our commodity derivative contracts of $16.7 million. Also included in the 2008 period is a realized loss of $1.1 million related to our interest rate swap offset by a change in the fair value of our interest rate swap of $0.3 million. For additional details about our derivatives, refer to Item 1 Financial Statements – Note 7 – Derivative Financial Instruments.

Interest expense. Interest expense incurred decreased to $24.2 million for the six months ended June 30, 2009 from $26.8 million for the six months ended June 30, 2008 primarily due to lower interest rates and lower debt outstanding during the 2009 period. During the 2009 and 2008 periods, $3.5 million and $10.4 million, respectively, of interest expense was capitalized to unevaluated oil and natural gas properties.

Loss on extinguishment of debt. In May 2009, we repaid the Tranche B term loan facility in full with borrowings under our revolving loan facility. During the six months ended June 30, 2009, we recorded a loss of $2.9 million related to the write-off of all the deferred financing costs related to the Tranche B term loan facility and the write-off of a portion of the deferred financing costs related to the revolving loan facility, as well as the incurrence of other incidental costs in connection with the payoff of the Tranche B term loan facility.

Other income. Other income, consisting of interest income, decreased to $0.7 million for the six months ended June 30, 2009 from $5.1 million for the same period in 2008 due to lower average daily cash balances and a reduction in market interest rates received on invested cash.

Income tax expense/benefit. An income tax benefit of $34.5 million was recorded during the six months ended June 30, 2009, compared to income tax expense of $111.9 million for the same period in 2008. The income tax benefit in 2009 resulted from a pre-tax loss of $271.2 million, only a portion of which is expected to be available to be carried back to 2007, which is the only open tax year that is currently available. Our effective tax rate for the six months ended June 30, 2009 was approximately 12.7% and primarily reflects the effect of a valuation allowance for our deferred tax assets. Our effective tax rate for the six months ended June 30, 2008 was approximately 34% and reflected the anticipated utilization of the deduction attributable to qualified domestic production activities under Section 199 of the Internal Revenue Code.

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, bank borrowings and our 8.25% Senior notes. 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 six months ended June 30, 2009 was $46.4 million, compared to net cash provided by operating activities of $548.0 million for the comparable period in 2008. Net cash used in investing activities totaled $226.5 million and $401.5 million during the first six months of 2009 and 2008, respectively, which primarily represents our investment in oil and natural gas properties. At June 30, 2009, we had a cash balance of $100.7 million and we had $262.4 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 oil prices have showed some signs of recovery since the end of 2008, they have continued to be significantly below the peak levels they reached in July 2008. At the end of 2008, the price of oil was approximately $41 per barrel, and during the first six months of 2009 our average realized price on sales of our oil increased to $44.93 per barrel. The price of oil was approximately $70 per barrel at the end of June 2009. Natural gas prices have continued to weaken. At the end of 2008, the price of natural gas was approximately $5.70 per Mcf, and during the first six months of 2009 our average realized price on sales of our natural gas decreased to $4.47 per Mcf. The price of natural gas was approximately $3.84 per Mcf at the end of June 2009, with no visible signs of near term recovery. Although our average realized sales prices for oil and natural gas were relatively weak during the first six months of 2009, the costs of goods and services that we consume in our normal operations remained proportionately high during the same time period as a result of commitments in 2008, which dramatically reduced our cash flows.

As a result of Hurricanes Ike and Gustav, our production and cash flow were negatively affected by the downtime experienced by third party pipelines and processing facilities and, to a lesser extent, by damage to our facilities. Prior to Hurricane Gustav in late August 2008, our production was averaging approximately 324 MMcfe per day. During the fourth quarter of 2008, our production averaged approximately 176 MMcfe per day and during the first six months of 2009, our production averaged approximately 255 MMcfe per day due to both hurricane damage and natural reservoir declines. As a result of both lower production volumes and significantly lower oil and natural gas prices, our operating cash flow was weak in both the fourth quarter of 2008 and the first six months of 2009. We expect additional third party pipelines to return to service during 2009 that will allow for additional

production volumes, but the impact on operating cash flow is not expected to be significant. During the second quarter of 2009, production of approximately 24 MMcfe per day remained shut-in due to hurricane damage. At current price levels and production volumes, cash flows will continue to be below the levels achieved in 2008.

From time to time, we have used 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. Currently, our only derivative instrument is 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 7 – Derivative Financial Instruments.

Disruptions in the Capital Markets and Impact on Liquidity. Although there have been significant disruptions in the U.S. and global capital markets, we have not experienced any disruptions to our liquidity. 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 2009, our lenders reduced the borrowing base from $710 million to $405.5 million. In May 2009, the Company paid in full the Tranche B term loan facility outstanding balance of $204.75 million plus accrued and unpaid interest of $0.7 million with borrowings under the revolving loan facility. At June 30, 2009, our cash on hand was $100.7 million and we had $262.4 million of undrawn capacity under our revolving loan facility, which matures in 2012. Sixteen 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 the continuing disruptions in the capital markets and our current credit rating, it could be difficult to obtain debt or equity capital funding in the future.

Insurance for damage from hurricanes in the Gulf of Mexico. 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. The policy limits 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.

Since the third quarter of 2008, we have spent $19.3 million to plug and abandon wells and facilities as a result of damage caused by Hurricane Ike. In addition, at June 30, 2009, we recorded a $44.2 million liability related to incremental costs of plugging and abandonment of wells in connection with two platforms toppled by Hurricane Ike, which are scheduled to be completed within the next year. 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, and has indicated that our insurance policies provide coverage for such costs and they are within policy limits, we have recognized an insurance receivable. Included in insurance receivables at June 30, 2009 is $50.2 million related to the dismantlement and plugging and abandonment of wells and facilities damaged as a result of Hurricane Ike.

Due to increased loss experience in recent years with hurricanes in the Gulf of Mexico and current turmoil in the financial 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 86.5% of our PV-10 value at December 31, 2008 are covered under our new insurance policies for hurricane damage. We do not carry business interruption insurance. 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. On May 1, 2009, 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 six months ended June 30, 2009, capital expenditures for oil and natural gas properties and equipment of $239.7 million included $80.2 million for exploration activities, $144.2 million for development activities and $15.3 million for seismic, capitalized interest and other leasehold costs. Our development and exploration capital expenditures consisted of $30.8 million in the deepwater, $0.3 million on the deep shelf and $193.3 million on the conventional shelf and other projects. Our capital expenditures for the six months ended June 30, 2009 were financed by cash from operating activities and cash on hand.

As a result of continued economic uncertainty and significantly lower cash flows, our drilling and capital expenditures in 2009 will be less than our drilling and capital expenditures in 2008. Our capital expenditure budget for 2009 is expected to approximate up to $270 million (including approximately $30 million during the remainder of 2009) and includes estimates for the completion of wells that were in progress at the end of 2008, wells or projects that we are presently committed to, lease saving operations, development wells where the rig is on location, scheduled recompletions, expenditures in connection with our non-operated properties and the development of our Green Canyon Block 646 prospect (“Daniel Boone”). We anticipate fully funding our remaining 2009 capital expenditures with internally generated cash flow and cash on hand. Our capital expenditure budget does not include any amounts for potential acquisitions.

Long-term debt. During the first quarter of 2009, we made a principal payment of $0.8 million on our Tranche B term loan facility. In May 2009, we paid in full the Tranche B term loan facility outstanding balance of $204.75 million plus accrued and unpaid interest of $0.7 million with borrowings under the revolving loan facility. In June 2009, we repaid $62.9 million under the revolving loan facility. During the quarter ended June 30, 2009, we recorded a loss of $2.9 million related to the write-off of all the deferred financing costs related to the Tranche B term loan facility and the write-off of a portion of the deferred financing costs related to the revolving loan facility, as well as the incurrence of other incidental costs in connection with the payoff of the Tranche B term loan facility. At June 30, 2009, borrowings of $142.5 million were outstanding on our revolving loan facility, all of which are classified as long-term. Also at June 30, 2009, we had $0.6 million of letters of credit outstanding and we had $262.4 million of undrawn capacity under the revolving loan facility. Borrowings outstanding under our 8.25% Senior notes were $450.0 million at June 30, 2009, all of which are classified as long-term. For additional details about our long-term debt, refer to Item 1 Financial Statements – Note 6 – Long-Term Debt.

As discussed above, our borrowing base under the Credit Agreement was redetermined by our lenders in April 2009, resulting in a new borrowing base of $405.5 million, of which $262.4 million was available for borrowing as of June 30, 2009. The Credit Agreement contains various financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio, a minimum asset coverage ratio and a maximum leverage ratio, as such ratios are defined in the Credit Agreement. In connection with the April 2009 borrowing base redetermination, we amended the maximum leverage ratio, which is the ratio of total debt to EBITDA (as those terms are defined in the Credit Agreement), to be 3.75 to 1 for the four quarters ended September 30, 2009, 3.50 to 1 for the four quarters ended December 31, 2009, 3.25 to 1 for the four quarters ended March 31, 2010 and 3.00 to 1 thereafter. We were in compliance with all applicable covenants of the Credit Agreement as of June 30, 2009.

Asset retirement obligations. In connection with the sale of certain assets during the second quarter of 2009, we reduced our asset retirement obligations by $75.2 million. Additionally, during the six months ended June 30, 2009, we increased our asset retirement obligations by $41.7 million, the majority of which relates to bids received from external third parties and revised estimates for the dismantlement of two operated platforms that were toppled during Hurricane Ike and the plugging and abandonment of the associated wells. We anticipate fully funding our remaining 2009 expenditures for asset retirement obligations with internally generated cash flow, cash on hand and proceeds from insurance. For additional details about our asset retirement obligations, refer to Item 1 Financial Statements – Note 4 – Asset Retirement Obligations.

Dividends. During the six months ended June 30, 2009, we paid regular cash dividends of $0.06 per common share. During the six months ended June 30, 2008, we paid regular cash dividends of $0.06 per common share and a special cash dividend of $30.0 million, or approximately $0.39 per common share. On August 3, 2009, our board of directors declared a cash dividend of $0.03 per common share, payable on September 17, 2009 to shareholders of record on August 20, 2009.

Repurchases of common stock. In March 2009, we announced by press release a $25 million stock repurchase program. Under the program, shares may be purchased from time to time at prevailing prices in the open market, in block transactions, in privately negotiated transactions or accelerated share repurchase programs through December 31, 2009, in accordance with Rule 10b-18 under the Exchange Act. The timing and actual number of shares purchased will depend on a variety of factors, such as the price of our common stock, corporate and regulatory requirements, alternative investment opportunities and other market and economic conditions. The repurchase program does not obligate us to acquire any specific number of shares and may be discontinued at any time. Repurchases will be funded with cash on hand. During the six months ended June 30, 2009, we purchased 1,429,486 shares of our common stock for approximately $9.2 million in the open market in accordance with the repurchase program.

Contractual obligations. Except as described in “Long-term debt” and “Asset retirement obligations” above, information about contractual obligations for the six months ended June 30, 2009, did not change materially from the disclosures in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2008.

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, 2008. Also refer to the Notes to Condensed Consolidated Financial Statements included in Part 1, Item 1 of this report.

For a description of recent accounting pronouncements, see Item 1 Financial Statements – Note 2 – Recent Accounting Pronouncements, Note 7 – Derivative Financial Instruments and Note 12 – Earnings (Loss) Per Share.

Information about market risks for the three and six months ended June 30, 2009, did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2008 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, 2008.

Interest Rate Risk. We have an interest rate swap 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 7 – 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 Securities and Exchange Commission 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 June 30, 2009 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 Securities and Exchange Commission’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 June 30, 2009, 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.

Our Annual Report on Form 10-K for the year ended December 31, 2008 includes a detailed discussion of our risk factors. There have been no material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008, except for the following items. The information presented below updates and should be read in conjunction with the risk factors and information disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008.

Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

President Obama’s Proposed Fiscal Year 2010 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other

similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

The following matters were submitted to a vote of shareholders during our Annual Meeting of Shareholders held on May 4, 2009.

Election of Directors. Our shareholders elected the seven nominees for director to serve until the 2010 Annual Meeting of Shareholders by the following vote:

Proposal to Increase Shares under Long-Term Incentive Compensation Plan. Our shareholders approved an increase in the number of shares available for issuance under the Bonus Plan of 2,000,000 shares by the following vote:

Ratification of Appointment of Independent Accountants. Our shareholders ratified the appointment of Ernst & Young LLP, independent registered public accountants, to audit our consolidated financial statements as of and for the year ending December 31, 2009, by the following vote:

The exhibits to this report are listed in the Exhibit Index appearing on page 26 hereof.

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on August 4, 2009.


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)


		Page
PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008	1
	Condensed Consolidated Statements of Income (Loss) for the Three and Six Months Ended June 30, 2009 and 2008	2
	Condensed Consolidated Statement of Changes in Shareholders’ Equity for the Six Months Ended June 30, 2009	3
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008	4
	Notes to Condensed Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	22

Item 4.	Controls and Procedures	23

PART II – OTHER INFORMATION

Item 1A.	Risk Factors	23

Item 4.	Submission of Matters to a Vote of Security Holders	24

Item 6.	Exhibits	24

SIGNATURE		25

EXHIBIT INDEX		26


	June 30, 2009			December 31, 2008
	(In thousands, except share data)
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	100,733		$	357,552
Receivables:
Oil and natural gas sales		53,538			36,550
Joint interest and other		61,703			83,178
Insurance		55,579			2,040
Income taxes		50,876			34,077

Total receivables		221,696			155,845
Prepaid expenses and other assets		55,153			30,417

Total current assets		377,582			543,814
Property and equipment – at cost:
Oil and natural gas properties and equipment (full cost method, of which $101,467 at June 30, 2009 and $99,139 at December 31, 2008 were excluded from amortization)		4,832,494			4,684,730
Furniture, fixtures and other		14,850			14,370

Total property and equipment		4,847,344			4,699,100
Less accumulated depreciation, depletion and amortization		3,586,368			3,217,759

Net property and equipment		1,260,976			1,481,341
Restricted deposits for asset retirement obligations		24,136			24,138
Deferred income taxes		11,877			—
Other assets		7,494			6,893

Total assets	$	1,682,065		$	2,056,186


Liabilities and Shareholders’ Equity
Current liabilities:
Current maturities of long-term debt	$	—		$	3,000
Accounts payable		205,373			228,899
Undistributed oil and natural gas proceeds		25,997			29,716
Asset retirement obligations		101,488			67,007
Accrued liabilities		10,719			18,254
Deferred income taxes		11,877			—

Total current liabilities		355,454			346,876
Long-term debt, less current maturities – net of discount		592,500			650,172
Asset retirement obligations, less current portion		402,945			480,890
Other liabilities		3,149			6,021
Commitments and contingencies
Shareholders’ equity:
Common stock, $0.00001 par value; 118,330,000 shares authorized; 77,817,032 issued and 76,387,546 outstanding at June 30, 2009; 76,291,408 issued and outstanding at December 31, 2008		1			1
Additional paid-in capital		376,336			372,595
Retained earnings (accumulated deficit)		(38,726	)		200,274
Treasury stock, at cost		(9,247	)		—
Accumulated other comprehensive loss		(347	)		(643	)

Total shareholders’ equity		328,017			572,227

Total liabilities and shareholders’ equity	$	1,682,065		$	2,056,186


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(In thousands, except per share data)
	(Unaudited)

Revenues	$	150,432		$	461,015		$	267,854		$	817,510


Operating costs and expenses:
Lease operating expenses		54,080			54,329			104,311			104,151
Production taxes		580			3,170			1,290			5,362
Gathering and transportation		3,755			4,755			6,350			11,384
Depreciation, depletion and amortization		74,515			143,908			155,303			279,877
Asset retirement obligation accretion		10,080			9,927			20,827			19,446
Impairment of oil and natural gas properties		—			—			205,030			—
General and administrative expenses		10,731			11,062			22,167			23,637
Derivative loss		460			23,767			852			36,071

Total costs and expenses		154,201			250,918			516,130			479,928

Operating income (loss)		(3,769	)		210,097			(248,276	)		337,582
Interest expense:
Incurred		11,740			12,461			24,249			26,839
Capitalized		(1,722	)		(4,762	)		(3,504	)		(10,435	)
Loss on extinguishment of debt		2,926			—			2,926			—
Other income		218			2,691			723			5,131

Income (loss) before income tax expense (benefit)		(16,495	)		205,089			(271,224	)		326,309
Income tax expense (benefit)		(10,521	)		70,479			(34,513	)		111,893

Net income (loss)	$	(5,974	)	$	134,610		$	(236,711	)	$	214,416


Basic and diluted earnings (loss) per common share	$	(0.08	)	$	1.76		$	(3.14	)	$	2.81
Dividends declared per common share	$	0.03		$	0.03		$	0.06		$	0.06


					Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)							Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity
	Common Stock										Treasury Stock
	Shares		Value								Shares	Value
	(In thousands)
	(Unaudited)
Balances at December 31, 2008	76,291		$	1	$	372,595		$	200,274		—	$	—		$	(643	)	$	572,227
Cash dividends	—			—		(2,289	)		(2,289	)	—		—			—			(4,578	)
Share-based compensation	—			—		3,116			—		—		—			—			3,116
Restricted stock issued, net of forfeitures	1,526			—		2,914			—		—		—			—			2,914
Net loss	—			—		—			(236,711	)	—		—			—			(236,711	)
Repurchase of common stock	(1,429	)		—		—			—		1,429		(9,247	)		—			(9,247	)
Other comprehensive income, net of tax	—			—		—			—		—		—			296			296

Balances at June 30, 2009	76,388		$	1	$	376,336		$	(38,726	)	1,429	$	(9,247	)	$	(347	)	$	328,017

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Balance, December 31, 2008	$	547,897
Liabilities settled		(30,969	)
Accretion of discount		20,827
Disposition of properties		(75,161	)
Liabilities incurred		134
Revisions of estimated liabilities		41,705

Balance, June 30, 2009		504,433
Less current portion		101,488

Long-term	$	402,945


	June 30,		December 31,
	2009		2008
Revolving loan facility, due July 2012	$	142,500	$	—
Tranche B term loan facility, net of unamortized discount of $2,328 at December 31, 2008		—		203,172
8.25% Senior notes, due June 2014		450,000		450,000

Total long-term debt		592,500		653,172
Current maturities of long-term debt		—		(3,000	)

Long-term debt, less current maturities	$	592,500	$	650,172


	Restricted Shares		Weighted Average Grant Date Price Per Share
Nonvested at December 31, 2008	233,703		$	30.33
Granted	1,570,436			6.91
Vested	(30,495	)		15.31
Forfeited	(44,812	)		11.62

Nonvested at June 30, 2009	1,728,832			9.81


	Three Months Ended June 30,										Six Months Ended June 30,
	2009			2008		Change			%		2009			2008		Change			%
	(In thousands, except percentages and per share data)
Financial:
Revenues:
Oil	$	98,532		$	265,074	$	(166,542	)	(62.8	)%	$	152,127		$	467,586	$	(315,459	)	(67.5	)%
Natural gas		51,895			195,852		(143,957	)	(73.5	)%		115,716			349,766		(234,050	)	(66.9	)%
Other		5			89		(84	)	(94.4	)%		11			158		(147	)	(93.0	)%

Total revenues		150,432			461,015		(310,583	)	(67.4	)%		267,854			817,510		(549,656	)	(67.2	)%
Operating costs and expenses:
Lease operating expenses (1)		54,080			54,329		(249	)	(0.5	)%		104,311			104,151		160		0.2	%
Production taxes		580			3,170		(2,590	)	(81.7	)%		1,290			5,362		(4,072	)	(75.9	)%
Gathering and transportation		3,755			4,755		(1,000	)	(21.0	)%		6,350			11,384		(5,034	)	(44.2	)%
Depreciation, depletion, amortization and accretion		84,595			153,835		(69,240	)	(45.0	)%		176,130			299,323		(123,193	)	(41.2	)%
Impairment of oil and natural gas properties (2)		—			—		—		—			205,030			—		205,030		—
General and administrative expenses		10,731			11,062		(331	)	(3.0	)%		22,167			23,637		(1,470	)	(6.2	)%
Derivative loss		460			23,767		(23,307	)	(98.1	)%		852			36,071		(35,219	)	(97.6	)%

Total costs and expenses		154,201			250,918		(96,717	)	(38.5	)%		516,130			479,928		36,202		7.5	%

Operating income (loss)		(3,769	)		210,097		(213,866	)	(101.8	)%		(248,276	)		337,582		(585,858	)	(173.5	)%
Interest expense, net of amounts capitalized		10,018			7,699		2,319		30.1	%		20,745			16,404		4,341		26.5	%
Loss on extinguishment of debt		2,926			—		2,926		—			2,926			—		2,926		—
Other income		218			2,691		(2,473	)	(91.9	)%		723			5,131		(4,408	)	(85.9	)%

Income (loss) before income tax expense (benefit)		(16,495	)		205,089		(221,584	)	(108.0	)%		(271,224	)		326,309		(597,533	)	(183.1	)%
Income tax expense (benefit)		(10,521	)		70,479		(81,000	)	(114.9	)%		(34,513	)		111,893		(146,406	)	(130.8	)%

Net income (loss)	$	(5,974	)	$	134,610	$	(140,584	)	(104.4	)%	$	(236,711	)	$	214,416	$	(451,127	)	(210.4	)%

Basic and diluted earnings (loss) per common share (3)	$	(0.08	)	$	1.76	$	(1.84	)	(104.5	)%	$	(3.14	)	$	2.81	$	(5.95	)	(211.7	)%

	Three Months Ended June 30,										Six Months Ended June 30,
	2009			2008		Change			%		2009			2008		Change			%
Operating:
Net sales:
Natural gas (Bcf)		13.3			17.0		(3.7	)	(21.8	)%		25.9			34.7		(8.8	)	(25.4	)%
Oil (MMBbls)		1.9			2.3		(0.4	)	(17.4	)%		3.4			4.5		(1.1	)	(24.4	)%
Total natural gas and oil (Bcfe) (4)		24.8			31.0		(6.2	)	(20.0	)%		46.2			61.8		(15.6	)	(25.2	)%

Average daily equivalent sales (MMcfe/d)		272.6			340.3		(67.7	)	(19.9	)%		255.4			339.4		(84.0	)	(24.7	)%

Average realized sales prices:
Natural gas ($/Mcf)	$	3.89		$	11.53	$	(7.64	)	(66.3	)%	$	4.47		$	10.09	$	(5.62	)	(55.7	)%
Oil ($/Bbl)		51.61			113.74		(62.13	)	(54.6	)%		44.93			103.46		(58.53	)	(56.6	)%
Natural gas equivalent ($/Mcfe)		6.06			14.89		(8.83	)	(59.3	)%		5.79			13.23		(7.44	)	(56.2	)%

Average per Mcfe ($/Mcfe):
Lease operating expenses (1)	$	2.18		$	1.75	$	0.43		24.6	%	$	2.26		$	1.69	$	0.57		33.7	%
Gathering and transportation costs and production taxes		0.17			0.26		(0.09	)	(34.6	)%		0.17			0.27		(0.10	)	(37.0	)%
Depreciation, depletion, amortization and accretion		3.41			4.97		(1.56	)	(31.4	)%		3.81			4.85		(1.04	)	(21.4	)%
General and administrative expenses		0.43			0.36		0.07		19.4	%		0.48			0.38		0.10		26.3	%

	$	6.19		$	7.34	$	(1.15	)	(15.7	)%	$	6.72		$	7.19	$	(0.47	)	(6.5	)%


Total number of wells drilled (gross)		6			10		(4	)	(40.0	)%		10			14		(4	)	(28.6	)%
Total number of productive wells drilled (gross)		4			8		(4	)	(50.0	)%		7			12		(5	)	(41.7	)%


Nominee	For	Withheld
Tracy W. Krohn	58,714,414	10,831,908
J.F. Freel	50,661,344	18,884,978
Virginia Boulet	56,026,607	13,519,715
S. James Nelson, Jr.	68,750,300	796,022
Robert I. Israel	68,783,670	762,652
Samir G. Gibara	68,782,708	763,614
B. Frank Stanley	68,764,165	782,157


Exhibit Number		Description
10.1		Second Amendment to W&T Offshore, Inc. Long-Term Incentive Compensation Plan (incorporated by reference from Appendix B to the Company’s Definitive Proxy Statement on Schedule 14A filed April 17, 2009).

10.2		Third Amendment to W&T Offshore, Inc. Long-Term Incentive Compensation Plan (incorporated by reference from Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A filed April 17, 2009).

10.3		Seventh Amendment to Third Amended and Restated Credit Agreement, dated May 4, 2009 (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009).

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.


For	Against	Abstentions
59,717,588	9,796,170	32,564


For	Against	Abstentions
69,430,661	103,404	12,257