Exhibit 99.1

		NEWS RELEASE
		Contacts:
		Janet Yang, Finance Manager
FOR IMMEDIATE RELEASE		investorrelations@wtoffshore.com
		713-297-8024
		Danny Gibbons, SVP & CFO
		jgibbons@wtoffshore.com
		713-624-7326

W&T OFFSHORE REPORTS FOURTH QUARTER AND FULL

YEAR 2010 FINANCIAL AND OPERATIONAL RESULTS

HOUSTON — March 2, 2011 — W&T Offshore, Inc. (NYSE: WTI) today announces financial and operational results for the fourth quarter and full year 2010. Some of the highlights include:

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Tracy W. Krohn, Chairman and Chief Executive Officer, commented, “We had another great quarter with solid production, high realized oil prices, good earnings and cash flow. We were able to increase reserves in 2010 with two different acquisitions, which we expect to lead to increased production in 2011 as a result. We funded our entire capital expenditure program, including both acquisitions, with internally generated cash flow. As a result, we did not have to increase our debt levels nor did we need to sell any equity to accomplish these transactions. As we have historically indicated, we manage for cash and constantly seek acquisition and joint venture opportunities. We believe there continue to be important growth opportunities in the market place that will make sense for us and allow us to grow reserves and production and increase shareholder value. Our liquidity continues to be very strong, allowing us the ability to complete acquisitions when the right opportunity comes along.”

Revenues, Net Income and EPS: Net income for the fourth quarter of 2010 excluding special items was $29.6 million, or $0.40 per share. This compares to $26.7 million, or $0.35 per common share, reported for the fourth quarter of 2009, excluding special items. See the “Reconciliation of Net Income (Loss) to Net Income (Loss) Excluding Special

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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 the fourth quarter of 2010 was $20.5 million, or $0.27 per common share, on revenues of $187.0 million, compared to net income of $64.0 million and earnings per share of $0.84 on revenues of $176.1 million for the same period in 2009. Net income in the fourth quarter of 2009 benefitted from a one-time $38.4 million tax benefit due to tax legislation adopted in 2009. The Worker, Homeownership and Business Assistance Act of 2009, which extended the net operating loss carry-back period from two years to five years, resulted in additional tax benefits to us. Revenues were higher in the fourth quarter of 2010 due to higher realized oil prices and minimal changes in production.

Net income for 2010 was $117.9 million, or $1.58 per share, on revenues of $705.8 million. This compares to a net loss in 2009 of ($187.9) million, or ($2.51) loss per share, on revenues of $611.0 million. Net income for the year 2010, excluding special items, was $116.7 million, or $1.57 per share. For 2009, the net loss, excluding special items, was ($82.3) million, or ($1.10) loss per common share. The dramatic increase in earnings between periods is primarily due to an increase in our average realized sales prices, mainly due to oil price increases, and a reduction in most of our expenses. In addition, the 2009 period included a ceiling test impairment of $218.9 million. For 2010, lease operating expenses (“LOE”), depreciation, depletion, amortization and accretion (“DD&A”) and the derivative loss were all lower, the reasons for which are explained below.

Cash Flow from Operating Activities and Adjusted EBITDA: EBITDA and Adjusted EBITDA, and Adjusted EBITDA margin are non-GAAP financial measures and are defined and reconciled in “Non-GAAP Financial Information” later in this press release. Adjusted EBITDA for the fourth quarter of 2010 was $121.6 million compared to $115.1 million during the fourth quarter of the prior year. Adjusted EBITDA for the fourth quarter of 2010 benefitted from higher averaged realized sales prices.

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For 2010, Adjusted EBITDA was $450.2 million, an increase of 32% compared to $341.4 million for the year 2009. Net cash provided by operating activities for the full year of 2010 was $464.8 million, a significant increase over the $156.3 million reported for the prior year. The dramatic increase in cash flow was due to higher prices, lower operating expenses, a federal income tax refund of $99.8 million and insurance reimbursements of $65.5 million.

Production and Prices: During the fourth quarter of 2010, we sold 1.8 million barrels of oil and natural gas liquids at an average realized sales price of $77.27 per barrel and 11.9 Bcf of natural gas at an average realized sales price of $4.01 per Mcfe. In total we sold 22.6 Bcfe at an average realized sales price of $8.23 per Mcfe compared to 22.9 Bcfe sold at an average price of $7.67 per Mcfe, in the fourth quarter of the prior year. Production volumes were negatively affected in 2010 because of production shut in at our MP 108 field due to a third party pipeline outage that has continued since early June 2010.

For the year 2010, we sold 7.1 million barrels of oil and natural gas liquids at an average realized sales price of $71.65 per barrel and 44.7 Bcf of natural gas at an average realized sales price of $4.55 per Mcf. In total we sold 87.0 Bcfe at an average realized sales price of $8.15 per Mcfe, compared to 94.8 Bcfe sold at an average price of $6.39 per Mcfe in 2009. The 8% decline in production is largely attributable to divestitures completed in 2009, the production shut in at our MP 108 field, as well as natural reservoir declines, somewhat offset by partial year production from the newly acquired properties from Shell and Total.

Lease Operating Expenses: For the fourth quarter of 2010, total LOE was $47.5 million, up slightly from $45.8 million reported in the prior year’s fourth quarter. Despite adding the Shell deepwater properties, most of the components of LOE were lower in 2010 compared to 2009 with the exception of one notable item. Facilities costs, which is a component of LOE, increased $6.8 million, about 40% of which can be

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attributed to repairs to newly acquired properties, while the remainder relates to pipeline and compressor repairs and blast and paint work. Also of note, for both the fourth quarter of 2010 and the fourth quarter of 2009, insurance reimbursements exceeded hurricane remediation costs that are included in LOE. The reduction in LOE as a result of these items was greater in the fourth quarter of 2009 than the comparable 2010 amount. Insurance premiums that are included in LOE decreased $3.4 million in the fourth quarter of 2010 compared to the fourth quarter of 2009 due to a policy renewal effective June 1, 2010 covering well control and hurricane damage.

LOE for the year 2010 was $169.7 million, or $1.95 per Mcfe, down considerably from the $203.9 million, or $2.15 per Mcfe, reported for the prior year. LOE decreased for the year 2010 due to the 2009 property divestitures and the significant reduction in hurricane repairs, net of insurance reimbursements in 2010 compared to 2009. Included in lease operating expenses for 2010 is a net reduction to LOE of $11.7 million (insurance reimbursements exceeded hurricane remediation costs). This compares to an increase to LOE of $18.4 million for hurricane remediation costs in excess of insurance reimbursements in the prior year. Increases to LOE for the year were the costs to operate the new properties, higher workover expenditures associated with rig activity to perform certain workovers and greater facilities work associated with the new properties.

Depreciation, depletion, amortization and accretion: DD&A decreased to $73.6 million, or $3.25 per Mcfe, in the fourth quarter of 2010 compared to $78.3 million, or $3.42 per Mcfe, in the fourth quarter of the prior year. DD&A for the year 2010 was $294.1 million, or $3.38 per Mcfe, compared to $342.5 million, or $3.61 per Mcfe, for the year 2009. DD&A is lower due to lower production volumes and an increase in proved reserves.

Capital Expenditures, Acquisitions and Operations Update: For 2010, our capital expenditures excluding acquisitions were $178.7 million and our expenditures for acquisitions were $236.9 million. Acquisitions included $115.0 million to acquire the Total properties and $121.9 million to acquire the Shell properties. Other capital

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expenditures were made up of $60.2 million for exploration activities, $77.2 million for development activities and $41.4 million for seismic, leasehold and other costs. Capital expenditures and acquisitions for 2010 were funded from cash flow from operating activities and cash on hand. Capital expenditures in 2009 were $276.1 million, and no significant acquisitions were completed in 2009.

During 2010, we participated in the drilling of six offshore and two onshore wells. Five of the six offshore wells were successful, but neither of the onshore wells, which were both high risk but high potential exploration opportunities, were commercial. All five of the successful wells were on the conventional shelf and four were exploration wells and one was a development well. We operate three of the five successful wells.

Drilling Highlights: In the fourth quarter of 2010, the Company drilled the Main Pass 108 E-3 well. This well logged over 300 feet of net vertical pay in six sands. This is a conventional shelf exploration well in which we own a 100% working interest.

After the close of the fourth quarter, the Company drilled two wells. One of the wells is an onshore well in Southeast Texas in which we own a 50% non-operated working interest. The well found 22 feet of gas condensate pay, and we expect it to be online before the end of the first quarter of 2011. The second well is the Main Pass 180 A-2 well in which we own a 100% working interest. The well reached a total vertical depth of 13,950 feet and found approximately 91 feet of high quality gas sands in three separate zones.

Reserves: At December 31, 2010, total proved reserves were 485.4 Bcfe, compared to proved reserves of 371.0 Bcfe at the end of 2009. The 31% increase in proved reserves is primarily due to the newly acquired properties from Shell and Total, success with the drill bit and positive revisions, which are partially offset by production. Year-end 2010 proved reserves are comprised of 53% natural gas and 47% oil and natural gas liquids based on a ratio of six Mcf to one barrel equivalent. In accordance with guidelines established by the SEC, our proved reserves as of December 31, 2010 were determined to

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be economically producible under existing economic conditions, which requires the use of the 12-month average price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price for the period January 2010 through December 2010. The present value of our total proved reserves only, discounted at 10% (referred to as “PV-10”*) was $1.9 billion at December 31, 2010 excluding the effect of estimated asset retirement obligations. PV-10, including estimated asset retirement obligations, was $1.5 billion. This is based on average prices of $4.38 per Mcf for natural gas and $75.96 per Bbl for oil and natural gas liquids, adjusted for quality, transportation fees and regional price differentials. The estimate of proved reserves is based on a reserve report prepared by Netherland, Sewell & Associates, Inc., the Company’s independent petroleum consultant.

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The Company’s proved reserves are summarized in the table below:

2010 Reserve Reconciliation:

As stated above, proved reserve replacement for 2010 was 231%. Proved reserve replacement is a non-GAAP measure and is defined as the sum of revisions of previous estimates, extensions and recoveries, and purchases of mineral in place, divided by production.

2011 Capital Expenditures Budget: Our capital expenditure budget for 2011 is $310 million excluding acquisitions. The budget includes $161 million to drill and evaluate 14 wells, including 10 exploration and four development wells. The 14 wells are comprised of five on the conventional shelf, one in the deepwater, two on the deep shelf and six onshore. Three of the 14 wells are in progress. The remainder of the budget is allocated

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to well completions, facilities capital, such as compressor projects at Tahoe (VK 783) and MP 108, recompletions, seismic and leasehold items.

Outlook: The guidance for first quarter and full year 2011 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 first quarter and full year 2011 are shown in the table below. Production guidance includes the planned build up from our capital budget.

2011 Production and Cost Guidance:

Conference Call Information: W&T will hold a conference call to discuss financial and operational results on Wednesday, March 2, 2010 at 10:00 a.m. Eastern Time. To participate, dial (480) 629-9692 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 9, 2011, and may be accessed by calling (303) 590-3030 and using the pass code 4400979#.

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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 has grown through acquisition, exploitation and exploration and holds working interests in approximately 67 fields in federal and state waters and a majority of its daily production is derived from wells it operates. 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 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 our Annual Report on Form 10-K for the year ended December 31, 2009 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 (Loss)

(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 Financial 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,” “Adjusted EBITDA,” “Adjusted EBITDA Margin,” and “PV-10.” 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. We calculate Adjusted EBITDA margin by dividing Adjusted EBITDA for the period presented by total revenues for the same period. PV-10 is a term used in the industry that is not a defined term in generally accepted accounting principles. We define PV-10 as the present value of estimated future net revenues of estimated proved reserves as calculated by our independent petroleum consultant using a discount rate of 10%. This amount includes projected revenues, estimated production costs and estimated future development costs. PV-10 excludes cash flows for asset retirement obligations, general and administrative expenses, derivatives, debt service and income taxes. PV-10 including estimated asset retirement obligations uses a discount factor of 10% to compute the present value of the estimated asset retirement obligations.

Reconciliation of Net Income (Loss) to Net Income (Loss) Excluding Special Items

“Net Income (Loss) Excluding Special Items” does not include the unrealized derivative (gain) loss, the loss on extinguishment of debt, the impairment of oil and gas properties and associated tax effects and tax impact of the new tax legislation. Net Income (Loss) 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 (loss) plus income tax expense (benefit), net interest expense, depreciation, depletion, amortization, accretion and impairment of oil and gas properties. 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 commodity 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 (loss) to consolidated EBITDA and Adjusted EBITDA.

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