Exhibit 99.1

W&T OFFSHORE REPORTS THIRD QUARTER 2011 FINANCIAL

RESULTS AND YEAR-TO-DATE OPERATIONAL RESULTS

HOUSTON — October 31, 2011 — W&T Offshore, Inc. (NYSE: WTI) today provides financial results for the third quarter 2011 and year-to-date operational results. Some of the highlights include:

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Tracy W. Krohn, Chairman and Chief Executive Officer, commented, “We continued on with the momentum that started earlier this year. Production volumes are up and were beyond the high side of our expectations due to very little storm activity and better well

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performance. Our realized oil prices continued to be strong as we benefit from the premium pricing that our Gulf Coast barrels receive relative to WTI. We are continuing to generate significant cash flow as our adjusted EBITDA for the first nine months was over $470 million and our adjusted net income and EPS was well above year ago levels. Our move onshore has been expanded in a meaningful way to East Texas where we picked up approximately 141,000 acres as well as a number of new exploration opportunities.”

Revenues, Net Income and EPS: Net income for the third quarter of 2011 was $52.9 million, or $0.70 per common share, on revenues of $245.4 million, compared to net income for the third quarter of 2010 of $27.2 million, or $0.36 per common share, on revenues of $169.6 million. For the nine months ended September 30, 2011 net income totaled $126.8 million, or $1.68 per common share, on revenues of $709.1 million, compared to the first nine months of 2010 of $97.4 million, or $1.30 per common share, on revenues of $518.8 million. Net income increased in the third quarter of 2011 from the comparable 2010 period largely due to higher average oil and liquids prices, higher natural gas and liquids sales volumes and a gain on derivatives. The factors that contributed to the increase in net income were partially offset by higher costs and expenses and a higher effective tax rate. The effective tax rate for the third quarter was approximately 35.3 %, compared to 2.4% during the third quarter of 2010. For 2011 substantially all of our federal income tax is expected to be deferred except for the amount related to alternative minimum tax which required a small cash payment. The effective tax rate in the third quarter of last year differed from the statutory rate of 35% primarily due to a reversal of a portion of a previously established valuation allowance.

Net income for the third quarter of 2011, excluding special items, was approximately $42.4 million, or $0.56 per common share. Net income, excluding special items, for the corresponding quarter of 2010 was approximately $32.0 million, or $0.43 per common share. Net income for the nine months ended September 30, 2011, excluding special items, was approximately $128.5 million, or $1.70 per common share, compared to net income, excluding special items, of $87.1 million, or $1.17 per common share, in the

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corresponding period of 2010. See the “Non-GAAP Financial Measures - Reconciliation of Net Income to Net Income Excluding Special Items” table at the back of this press release for a description of the special items.

Cash Flow from Operating Activities and Adjusted EBITDA: EBITDA and Adjusted EBITDA are non-GAAP measures and are defined in the “Non-GAAP Financial Measures” section later in this press release. Net cash provided by operating activities for the nine months ended September 30, 2011 was $396.1 million, up from the $392.9 million reported for the first nine months of 2010. The 2010 period benefitted from a $99.8 million tax refund related to the Worker, Homeowner and Business Assistance Act of 2009 that allowed us to carry back losses to previously closed years, while 2011 reflects a tax payment of $25 million. Otherwise, net cash provided by operating activities has increased over $128 million due to the significant improvement in operating results.

Adjusted EBITDA for the third quarter of 2011 increased 37.0% to $161.5 million compared to $117.9 million reported in the third quarter of 2010. For the nine months ended September 30, 2011, Adjusted EBITDA increased 43.2% to $470.4 million from $328.6 million during the nine months ended September 30, 2010.

Production and Prices: Our oil sales for the third quarter of 2011 were 1.5 million barrels and our averaged realized sales price was $102.14 per barrel, which represents a $27.68 per barrel increase over third quarter of last year. NGLs sales were up 7.8 million gallons to 21.0 million gallons and the price increased $0.42 a gallon to $1.34 per gallon. Natural gas sales for the quarter were 14.3 Bcf sold at an average price of $4.27 per Mcf, which is about $0.20 per Mcf less than the average for the third quarter of 2010. On a natural gas equivalent basis, we sold 26.5 Bcfe at an average price of $9.26 per thousand cubic feet of gas equivalent (“Mcfe”) in the third quarter of 2011, 46% of which was oil and NGLs. This compares to 21.6 Bcfe sold at an average price of $8.02 per Mcfe in the third quarter of 2010, 51% of which was oil and NGLs. Sales volumes were higher primarily due to the acquisition of the Shell properties in the fourth quarter of 2010 and

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the Permian Basin Properties during the second quarter of this year. Sales volumes also benefitted from the return to production of various fields that were shut-in by the pipeline outage in the Main Pass 108 field. Those fields returned to service on March 31, 2011 when a connecting pipeline became operational. Production from that area averaged approximately 44 million cubic feet equivalent (“MMcfe”) per day during the month of September.

Lease Operating Expenses (“LOE”): In the third quarter of 2011, LOE was $58.9 million or $2.22 per Mcfe compared to $34.4 million or $1.59 per Mcfe in the third quarter of 2010. On a component basis, base LOE was up $10.1 million, workover expenses rose by $4.3 million and insurance premiums increased by $2.1 million. In addition, hurricane insurance reimbursements fell by $7.0 million from the third quarter of 2010 to $0.5 million for the third quarter of 2011. Base LOE is up primarily due to the various acquisitions completed in 2010 and 2011. Workover costs are up primarily due to the Permian Basin properties and insurance premiums are up due to the insurance renewals associated with substantially expanded coverage as a result of recent acquisitions both onshore and offshore.

For the nine months ended September 30, 2011, LOE increased to $159.9 million, or $2.16 per Mcfe, compared to $122.2 million, or $1.90 per Mcfe, for the like 2010 period. LOE for the first nine months of 2011 included an increase to base LOE of $15.3 million due mostly to the acquisition of properties in 2010 and 2011. In addition, facilities expense rose nearly $11.0 million to $21.4 million from a year ago due mostly to work on the tendon tension monitoring system and other repair work at Matterhorn, repair work at Virgo, pipeline repairs at Ship Shoal 300 and field maintenance at Tahoe. The 2010 period also included insurance reimbursements of about $9.9 million compared to a cumulative net zero balance for the first nine months of 2011.

Depreciation, depletion, amortization and accretion (“DD&A”): The DD&A rate for the third quarter of 2011 decreased to $3.19 per Mcfe from $3.48 per Mcfe for the same period in 2010 due to an increase in proved reserves. DD&A on a nominal basis

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increased to $84.5 million for the third quarter of 2011 from $75.3 million in the third quarter of 2010 primarily due to higher production volumes. The increase in proved reserves, as a result of adding the Permian Basin properties, has also increased our reserves to production profile in 2011 compared to 2010 from 5.6 to 7.7 years. DD&A on a per Mcfe basis decreased to $3.27 for the first nine months of 2011 from $3.42 per Mcfe in the comparable 2010 period due to an increase in proved reserves. DD&A on a nominal basis for the nine months ended 2011 increased to $241.9 million compared to $220.5 million for the same period in 2010 due to higher production volumes.

General and Administrative Expenses (“G&A”): G&A increased to $18.1 million for the third quarter of 2011 from $13.4 million for the same period in 2010, primarily due to higher employee incentive compensation as a result of improved financial and operational performance, and expanded activities onshore and offshore. In addition, costs associated with acquisition activities, transition service fees paid to the sellers of the properties we acquired in 2010 and 2011, litigation costs and accruals, and increased professional fees also resulted in higher G&A. On a per Mcfe basis, G&A was $0.68 per Mcfe for the third quarter of 2011, compared to $0.62 per Mcfe for the same period in 2010.

Capital Expenditures and Operations Update: For the nine months ended September 30, 2011, capital expenditures were $619.8 million, including $434.6 million for acquisitions, $40.0 million for exploration and $128.3 million for development activities and $16.9 million for seismic, capitalized interest and other leasehold costs.

Drilling Highlights

Offshore: In the third quarter of 2011, we successfully drilled the Main Pass 108 No. 8 well. The well reached a total measured depth of 12,878 feet and found seven pay sands. We own a 100% working interest in this well and are currently in the process of completing this conventional shelf development well.

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Onshore: During the third quarter of 2011, we drilled 12 development wells and seven exploration wells in West Texas, all of which were successful. In addition, we drilled two exploration wells in other areas of Texas, one of which was successful.

Outlook:

The guidance for fourth quarter and full year 2011 represents our best estimate of future results, and is affected by the factors described below in “Forward-Looking Statements.”

Guidance for the fourth quarter and full year 2011 is shown in the table below. Production guidance includes the planned build up from our capital budget.

Fourth Quarter and Revised Full-Year 2011 Production and Cost Guidance:

Conference Call Information: We will hold a conference call to discuss financial and operational results on Tuesday November 1, 2011 at 11:00 a.m. Eastern Time / 10:00 a.m. Central Time. To participate, dial (303) 590-3030 and ask for the W&T Offshore call at least ten minutes before the call begins. The call will also be broadcast live over the Internet from our website at www.wtoffshore.com. A replay of the conference call will be available approximately two hours after the end of the call until November 8, 2011, and may be accessed by calling 303-590-3030 and using the pass code 4480870#.

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About W&T Offshore

W&T Offshore is an independent oil and natural gas company focused primarily in the Gulf of Mexico, including exploration in the deepwater and deep shelf regions, where it has developed significant technical expertise. W&T Offshore has recently diversified its operations by expanding onshore into the Permian Basin and into East Texas. W&T Offshore has grown through acquisitions, exploitation and exploration, holds working interests in approximately 67 fields in federal and state waters, and has approximately 173,000 net acres under lease onshore. A majority of its daily production is derived from wells it operates offshore. For more information on W&T Offshore, please visit its Web site at www.wtoffshore.com.

Forward-Looking Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements reflect W&T Offshore’s current views with respect to future events, based on what it believes are reasonable assumptions. No assurance can be given, however, that these events will occur. These statements are subject to risks and uncertainties that could cause actual results to differ materially including, among other things, market conditions, oil and gas price volatility, uncertainties inherent in oil and gas production operations and estimating reserves, unexpected future capital expenditures, competition, the success of W&T Offshore’s risk management activities, governmental regulations, uncertainties and other factors discussed in W&T Offshore’s Annual Report on Form 10-K for the year ended December 31, 2010 and subsequent Form 10-Q reports found at www.sec.gov.

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W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Income

(Unaudited)

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W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Operating Data

(Unaudited)

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W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(Unaudited)

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W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(Unaudited)

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W&T OFFSHORE, INC. AND SUBSIDIARIES

Non-GAAP Information

Certain financial information included in our financial results are not measures of financial performance recognized by accounting principles generally accepted in the United States, or GAAP. These non-GAAP financial measures are “Adjusted Net Income,” “EBITDA” and “Adjusted EBITDA.” Our management uses these non-GAAP financial measures in its analysis of our performance. These disclosures may not be viewed as a substitute for results determined in accordance with GAAP and are not necessarily comparable to non-GAAP performance measures which may be reported by other companies.

Reconciliation of Net Income to Net Income Excluding Special Items

“Net Income Excluding Special Items” does not include the royalty relief recoupment, net of DD&A expense, the transportation allowance for deepwater production, the unrealized derivative (gain) loss, the loss on extinguishment of debt, and associated tax effects and tax impact of the new tax legislation. Net Income excluding special items is presented because the timing and amount of these items cannot be reasonably estimated and affect the comparability of operating results from period to period, and current periods to prior periods.

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Reconciliation of Net Income to Adjusted EBITDA

We define EBITDA as net income plus income tax expense, net interest expense, depreciation, depletion, amortization, and accretion. We believe the presentation of EBITDA and Adjusted EBITDA provide useful information regarding our ability to service debt and to fund capital expenditures and help our investors understand our operating performance and make it easier to compare our results with those of other companies that have different financing, capital and tax structures. Adjusted EBITDA excludes the unrealized gain or loss related to our derivative contracts, loss on extinguishment of debt, royalty relief recoupment and adjustments related to a transportation allowance for deepwater production. Although not prescribed under generally accepted accounting principles, we believe the presentation of EBITDA and Adjusted EBITDA are relevant and useful because they help our investors understand our operating performance and make it easier to compare our results with those of other companies that have different financing, capital and tax structures. EBITDA and Adjusted EBITDA should not be considered in isolation from or as a substitute for net income, as an indication of operating performance or cash flows from operating activities or as a measure of liquidity. EBITDA and Adjusted EBITDA, as we calculate them, may not be comparable to EBITDA and Adjusted EBITDA measures reported by other companies. In addition, EBITDA and Adjusted EBITDA do not represent funds available for discretionary use.

The following table presents a reconciliation of our consolidated net income to consolidated EBITDA and Adjusted EBITDA.

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