Exhibit 99.1

NEWS RELEASE

		Contact:   Janet Yang or Mark Brewer Investor Relations investorrelations@wtoffshore.com 713-297-8024   Danny Gibbons SVP & CFO investorrelations@wtoffshore.com 713-624-7326

W&T OFFSHORE REPORTS FOURTH QUARTER AND FULL YEAR

2011 FINANCIAL AND OPERATIONAL RESULTS

HOUSTON – February 23, 2012 – W&T Offshore, Inc. (NYSE: WTI) today announces financial and operational results for the fourth quarter and full year 2011. Some of the highlights include:

Tracy W. Krohn, Chairman and Chief Executive Officer, stated, “We had another great quarter and year. We followed through with our commitment and strategy to find and grow reserves and production, which provides increased value to all of our stakeholders. We reported our highest operating income in Company history with solid oil and liquids production and high oil prices. Over 84% of our oil production is on the Gulf Coast, which realized a significant premium over NYMEX priced crudes in 2011. We were able to grow our proved reserves with a reserve replacement ratio of 312% and saw the PV-10 of our proved reserves increase to $3.1 billion. As we previously announced, we increased our 2012 capital budget, excluding any potential acquisitions, to fund an increase in exploration and development activities. Our exploration activities make up 39% of our capital budget and development activities make up the remainder which will help sustain production and cash flow. As we have indicated, the mix of our

exploration activities provides the Company more exposure to larger reserves and extended development opportunities. Although our budget excludes acquisitions, we believe they are highly probable and will allow us to continue to again grow reserves and production in a meaningful way, which will drive total shareholder returns in 2012.”

Revenues, Net Income and EPS: Net income for the fourth quarter of 2011 was $46.1 million, or $0.61 per common share, on revenues of $261.9 million, compared to net income of $20.5 million and earnings per share of $0.27 on revenues of $187.0 million for the same period in 2010. Revenues were higher in the fourth quarter of 2011 due to higher realized oil and NGL prices and increased production. Net income for the fourth quarter of 2011, excluding special items, was $51.5 million, or $0.69 per share. This compares to $29.6 million, or $0.40 per common share, reported for the fourth quarter of 2010, excluding special items. See the “Reconciliation of Net Income to Net Income Excluding Special Items” and related earnings per share, excluding special items table under “Non-GAAP Financial Information” at the back of this press release for a description of the special items.

Net income for 2011 was $172.8 million, or $2.29 per share, on revenues of $971.0 million. This compares to net income in 2010 of $117.9 million, or $1.58 per share, on revenues of $705.8 million. Net income for the year 2011, excluding special items, was $179.9 million, or $2.38 per share. For 2010, net income, excluding special items, was $116.7 million, or $1.57 per common share. The increase in earnings between periods is primarily due to increases in oil and NGL prices and higher production volumes, partially offset by higher operating costs and lower natural gas prices.

Cash Flow from Operating Activities and Adjusted EBITDA: For 2011, Adjusted EBITDA was $646.5 million, an increase of 44% compared to $450.2 million for the year 2010. Net cash provided by operating activities for 2011 was $521.5 million, an increase over the $464.8 million reported for the prior year. Adjusted EBITDA and cash flows from operating activities increased due to higher oil and NGL prices and higher production volumes, partially offset by higher costs. Cash flows from operating activities in 2010 included a federal income tax refund of $99.8 million while the 2011 period includes tax payments of $35.7 million.

Production and Prices: During the fourth quarter of 2011, we sold 1.6 million barrels of oil, 0.6 million barrels of NGLs and 14.4 Bcf of natural gas at an average realized sales prices of $112.01 per barrel, $56.55 per barrel and $3.51 per Mcf, respectively. In total, we sold 4.6 MMBoe at an average realized sales price of $57.12 per Boe, compared to 3.8 MMBoe sold at an average realized sales price of $49.39 per Boe in the fourth quarter of the prior year.

For the year 2011, we sold 6.1 million barrels of oil, 1.9 million barrels of NGLs and 53.7 Bcf of natural gas at an average realized sales prices of $105.92 per barrel, $55.81 per barrel and $4.12 per Mcf, respectively. In total, in 2011 we sold 16.9 MMBoe at an average realized sales price of $57.32 per Boe, compared to 14.5 MMBoe sold at an average realized sales price of $48.87 per Boe for the prior year. The sales volume increase for oil and NGLs is primarily attributable to increases associated with properties acquired in 2011 and 2010. The sales volume increase for natural gas is primarily attributable to increases associated with our acquisition activities, the Main Pass 108 fields resuming production and successful exploration efforts. Over 80% of our production is from wells we operate.

Lease Operating Expenses: For the fourth quarter of 2011, lease operating expenses (“LOE”), which include base lease operating expenses, insurance, workovers, facility expenses, and hurricane remediation costs net of insurance claims, increased to $59.3 million, or $12.94 per Boe, from $47.5 million, or $12.59 per Boe, reported in the prior year’s fourth quarter. Increases in base lease operating expenses contributed 62%, or $7.3 million, of the increase in total LOE. Base lease operating expenses were higher in the fourth quarter of 2011 primarily due to expenses associated with the properties acquired in 2011 and 2010 and higher costs at our various non-operated properties.

LOE for the year 2011 was $219.2 million, up from the $169.7 million reported for the prior year. On a per Boe basis, LOE increased to $12.95 per Boe during 2011 compared to $11.70 per Boe during 2010. On a component basis, base lease operating expenses, facility expenses, hurricane remediation costs net of insurance claims, and workover costs increased $20.7 million, $14.1 million, $11.7 million and $3.6 million, respectively. As a partial offset, insurance premiums decreased $0.6 million. The increase in base lease operating expenses is primarily attributable to expenses associated with the properties acquired in 2011 and 2010, higher costs at our various non-operated properties, increased processing fees associated with our Daniel Boone field production and non-recurring expenses billed to a third party in 2010 related to a divestiture that did not reoccur in 2011. The increase in facility expenses is primarily attributable to work performed on the tendon tension monitoring system and mechanical repairs at our Matterhorn platform, pipeline repairs at our Ship Shoal 300 field to remove paraffin and inspection fees at our Main Pass 252 platform. Hurricane remediation costs net of insurance claims increased primarily due to higher reimbursements received in 2010. Workover costs increased due to work performed at our Yellow Rose Properties and expenses at the Main Pass 108 field, partially offset by projects in 2010 that did not reoccur in 2011.

Depreciation, depletion, amortization and accretion: Our DD&A rate decreased to $18.95 per Boe in the fourth quarter of 2011 from $19.50 per Boe in the fourth quarter of the prior year but on a nominal basis, DD&A increased to $86.9 million in the fourth quarter of 2011 from $73.6 million in the fourth quarter of 2010. DD&A for the year 2011 was $328.8 million, or $19.43 per Boe, compared to $294.1 million, or $20.28 per Boe, for the year 2010. DD&A is lower on a per Boe basis due to an increase in proved reserves. On a nominal basis, DD&A is higher due to higher production volumes.

General and Administrative Expenses (“G&A”): G&A increased to $20.1 million for the fourth quarter of 2011, up $4.9 million from the same period in 2010. For the year, G&A increased to $74.3 million from $53.3 million for 2010 primarily due to higher employee incentive compensation as a result of improved financial and operational performance, and expanded activities onshore and offshore. G&A was also higher due to costs associated with acquisition activities, surety premiums, transition services fees paid to sellers of the acquired properties, and litigation settlements and accruals. On a per Boe basis, G&A was $4.39 per Boe for 2011, compared to $3.67 per Boe for the same period in 2010.

Capital Expenditures, Acquisitions and Operations Update: For 2011, our capital expenditures were $719.0 million, comprised of $281.8 million for oil and gas expenditures and $437.2 million for acquisitions. Capital expenditures included $77.6 million for exploration activities, $179.7 million for development activities and $24.5 million for seismic, leasehold and other costs. Acquisitions included $394.4 million to acquire approximately 24,500 gross acres (21,900 net acres) of oil and gas leasehold interests in the West Texas Permian Basin (the “Yellow Rose Properties”) from Opal Resources LLC and Opal Resources Operating Company LLC (“Opal”). In addition, we acquired Shell Offshore Inc.’s (“Shell”) 64.3% interest in the Fairway Field along with a like interest in the associated Yellowhammer gas treatment plant (the “Fairway Properties”) for $42.8 million. Capital expenditures and acquisitions for 2011 were funded from cash flow from operating activities, cash on hand and long-term debt.

Drilling Highlights:

During 2011, we participated in drilling eight offshore wells and 46 onshore wells to total depth with an overall success rate of over 98%. All eight offshore wells and 45 of the 46 onshore wells were successful.

All three offshore exploratory wells and five development wells drilled in 2011 were on the conventional shelf. We are the operator of seven of these eight successful wells. Four of the eight offshore wells were drilled to total depth during the fourth quarter and are as follows:

Onshore, we drilled 46 onshore wells to total depth in 2011, of which 29 were in the Yellow Rose Properties, 13 wells were in Terry County in West Texas, two were in East Texas and two more were in other areas in Texas.

Since the end of the fourth quarter of 2011, we have drilled six development and one exploration wells to total depth in the Yellow Rose Properties and one exploration well in Terry County. We are also currently drilling the Ship Shoal 349 A-13 development well and one exploratory and two development wells located on the Yellow Rose Properties.

Reserves*: As previously disclosed, at December 31, 2011, total proved reserves increased 44% to 116.9 MMBoe, or 701.1 Bcfe, from 80.9 MMBoe, or 485.4 Bcfe, at the end of 2010. Our reserve replacement rate in 2011 was 312%. Oil and NGLs contributed 59% to total proved reserves at year-end 2011, compared to 47% at December 31, 2010. Proved developed reserves comprised 65% of total proved reserves at December 31, 2011. Excluding the effect of estimated ARO, PV-10 increased 63% from $1.9 billion at year-end 2010 to $3.1 billion at December 31, 2011. The estimate of proved reserves is based on a reserve report prepared by Netherland, Sewell & Associates, Inc., the Company’s independent petroleum consultant.

2012 Capital Expenditures Budget: Our capital expenditure budget for 2012 is $425 million excluding acquisitions. The budget includes $379 million to drill, evaluate and complete 75 wells, including 25 exploration and 50 development wells. The 25 exploration wells are comprised of five on the conventional shelf, one in the deepwater and 19 onshore. The 50 development wells are comprised of three on the conventional shelf, one in the deepwater and 46 onshore. The remainder of the budget is allocated to facilities capital, recompletions, seismic and leasehold items.

Outlook: The guidance for full year 2012 represents the Company’s best estimate of likely future results, and is affected by the factors described below in “Forward-Looking Statements.”

Guidance for the full year 2012 is shown in the table below. Production guidance includes the planned build up from our capital budget.

Conference Call Information: W&T will hold a conference call to discuss financial and operational results on Friday, February 24, 2012 at 10:00 a.m. Eastern Time. To participate, dial (480) 629-9818 a few minutes before the call begins. The call will also be broadcast live over the

Internet from the Company’s website at www.wtoffshore.com. A replay of the conference call will be available approximately two hours after the end of the call until March 1, 2012, and may be accessed by calling (303) 590-3030 and using the pass code 4506374#.

About W&T Offshore

W&T Offshore, Inc. 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 we have developed significant technical expertise. We recently diversified our operations by expanding onshore into the Permian Basin and into East Texas. We have grown through acquisitions, exploitation and exploration, hold working interests in approximately 60 producing or capable of producing offshore fields in federal and state waters, and have approximately 173,000 net acres under lease onshore. A substantial majority of our daily production is derived from wells we operate offshore. For more information on W&T Offshore, please visit our website at www.wtoffshore.com.

Non-GAAP Financial Measure

PV-10 of our proved reserves is the present value of future net revenues of our estimated proved reserves, discounted at 10%, before the effect of estimated ARO. PV-10 is a non-GAAP financial measure. It differs from the Standardized Measure of Discounted Future Net Cash Flows by excluding the discounted value of (i) estimated future ARO costs and (ii) estimated future income taxes. The discounted values of ARO costs and future income taxes are being evaluated and estimated in connection with completion of our 2011 financial statements.

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 our current views with respect to future events, based on what we believe 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 our 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 or at our website at www.wtoffshore.com under the Investor Relations section.

Our capital budget is subject to revision and reevaluation depending on future developments including drilling results, availability of crews and supplies, weather delays, significant changes in commodities prices and drilling costs.

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Income

(Unaudited)

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Operating Data

(Unaudited)

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(Unaudited)

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(Unaudited)

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.

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.