Exhibit 99.1

		PRESS RELEASE

W&T OFFSHORE REPORTS SECOND QUARTER 2012 FINANCIAL

AND OPERATIONAL RESULTS

HOUSTON – July 30, 2012 – W&T Offshore, Inc. (NYSE: WTI) today announces financial and operational results for the second quarter of 2012. Some of the highlights include:

“Cash flow from operating activities continues to be strong with high oil prices and higher production volumes which enhances our liquidity and allows us to fund our drilling and development program with internally generated cash flow,” stated Tracy W. Krohn, Chairman and Chief Executive Officer. “Our ability to generate cash, along with access to a $650 million revolving bank credit facility that is largely undrawn, creates sufficient visibility and flexibility to pursue new growth opportunities through both the drill bit and acquisitions. The acquisition environment continues to be active and we continue to vigorously evaluate opportunities as they arise. We also have attractive oil focused drilling projects this year and are pleased that our Gulf of Mexico oil production continues to benefit from premium oil pricing.”

W&T Offshore, Inc. — Nine Greenway Plaza, Suite 300 — Houston, Texas 77046 — 713-626-8525 — www.wtoffshore.com

Revenues, Net Income and EPS: Revenues for the second quarter of 2012 were $215.5 million compared to $252.9 million in the second quarter of 2011. Revenues were lower in the 2012 period, despite higher production volumes, due to lower realized sales prices for all of our products. The impact of lower prices on revenues was approximately $43.8 million, while the benefit of higher production volumes was approximately $6.7 million. Realized oil prices (unhedged) were $106.04 per barrel, down 4.5% compared to the same quarter of the prior year. Our realized oil sales price was above the average daily West Texas Intermediate price of $93.29 per barrel (the Brent price was $108.04 per barrel) due to higher premiums for offshore crude. Our realized natural gas sales price was $2.49 per Mcf representing a decline of 44.0% from the second quarter of 2011. Our realized NGLs sales price was $44.27 per barrel, which was 24.7% lower than the second quarter of 2011.

Net income for the second quarter of 2012 was $53.6 million, or $0.70 per common share, on revenues of $215.5 million, compared to net income of $55.2 million, or $0.73 per common share, on revenues of $252.9 million for the same period in 2011. Primarily due to lower realized sales prices, second quarter 2012 net income decreased compared to second quarter of 2011, partially offset by a $49.9 million derivative gain in the 2012 period. The effective tax rate was almost 39% and differs from the federal statutory rate of 35% primarily due to the recapture of previous deductions for qualified domestic production activities. Net income for the second quarter of 2012, excluding special items, was $21.0 million, or $0.28 per common share. This compares to $53.4 million, or $0.71 per common share, reported for the second quarter of 2011, excluding special items. See the “Reconciliation of Net Income to Net Income Excluding Special Items” and related earnings per share, excluding special items in the table under “Non-GAAP Financial Information” 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. For the second quarter of 2012, EBITDA was $185.0 million, up from the $178.4 million in the second quarter of 2011. EBITDA margin increased to 86%, up from the 71% in the prior year quarter. The 2011 period included a loss on early extinguishment of debt of $20.7 million. Adjusted EBITDA for the second quarter of 2012 was $134.9 million, a decrease of 23.2% compared to the $175.6 million for the second quarter of 2011. Our Adjusted EBITDA margin was 63% compared to 69% in the second quarter of 2011. Adjusted EBITDA is lower in the 2012 period primarily due to a decrease in our average realized sales price. Net cash provided by operating activities for the first half of 2012 was $241.3 million, up $11.5 million from the $229.8 million for the same period of the prior year.

Production and Prices: During the second quarter of 2012, we sold 1.5 million barrels of oil, 586,000 barrels of NGLs and 14.3 Bcf of natural gas. Our average realized sales price for oil was $106.04 per barrel, $44.27 per barrel for NGLs and $2.49 per Mcf for natural gas. In total, we sold 4.4 MMBoe at an average realized

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sales price of $48.71 per Boe, compared to 4.1 MMBoe sold at an average realized sales price of $61.01 per Boe in the second quarter of the prior year. Our production was affected by several pipeline outages that occurred during the quarter along with Tropical Storm Debby. The combined impact from the various downtimes was approximately 1.2 Bcfe or 0.2 MMBoe.

Lease Operating Expenses (“LOE”): For the second quarter of 2012, LOE, which includes base lease operating expenses, insurance, workovers, facility expenses, and hurricane remediation costs net of insurance claims, increased to $60.3 million from $48.6 million in the second quarter of 2011. Base LOE increased $8.2 million to $37.3 million primarily due to the Yellow Rose and Fairway acquisitions in May 2011 and August 2011, respectively. Workover costs were up $1.8 million to $7.5 million, insurance premiums were up $1.3 million to $7.9 million and facilities expenses were flat at $7.6 million. The increase in workovers reflects increased activities at our Yellow Rose properties and the higher insurance premiums reflect expanded coverage for our Gulf of Mexico properties.

Depreciation, depletion, amortization and accretion (“DD&A”): Our DD&A rate decreased slightly to $19.43 per Boe in the second quarter of 2012 from $20.14 per Boe in the second quarter of the prior year. On a nominal basis, DD&A increased to $85.9 million in the second quarter of 2012 from $83.4 million in the second quarter of 2011 due to higher production volumes.

General and Administrative Expenses (“G&A”): G&A was $14.6 million for the second quarter of 2012, down 18.8% from the $18.0 million reported in the second quarter of 2011. On a per Boe basis, G&A was $3.31 per Boe for the second quarter of 2012, compared to $4.35 per Boe for the same period in 2011. The decrease in G&A on a nominal basis is primarily due to a decrease in incentive compensation.

Derivative Gains and Losses: During the month of June, crude oil prices declined from the higher levels experienced earlier in the year. As a result, the mark to market loss on our derivative positions that was recorded in the first quarter was completely reversed, and a gain was recognized. The derivative gain in the second quarter was $49.9 million comprised of a $50.2 million unrealized gain, slightly offset by a $0.3 million realized loss. For the first six months of 2012 our commodity derivative gain was $10.2 million compared to a derivative loss of $6.5 million recorded in the first half of 2011. The commodity derivative positions are doing what they are designed to do which is reduce some of the impact of price volatility.

Capital Expenditures Update: For the six months ended June 30, 2012, our capital expenditures for oil and gas properties were $187.3 million and were funded with cash flow from operating activities. Capital expenditures included $101.1 million for onshore activities (split between $33.8 million for exploration and $67.3 million for development activities), $77.8 million for offshore activities (split between $3.1 million for exploration and $74.7 million for development) and $8.4 million for seismic, leasehold and other costs. Through the first six months of 2012 we have drilled and completed 39 wells in total, with 37 wells in West Texas and two wells in the Gulf of Mexico.

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Our 2012 Capital Budget estimated expenditures of $425.0 million and as indicated above we have spent $187.3 million through the first half of 2012. For the second half of 2012 we expect to spend approximately $70.0 million for onshore activities (split between $47.0 million for exploration and $23.0 million for development activities), $130.0 million for offshore activities (split between $86.0 million for exploration and $44.0 million for development) and $37.0 million for seismic, leasehold and other costs. These amounts could fluctuate up or down based on timing of third party operator decisions, permitting schedules and access to equipment, among other things. See the Operations Update below for a discussion of our planned deepwater well.

Operations Review and Update:

Gulf of Mexico

Wells Completed in Second Quarter 2012

During the second quarter of 2012, we completed and brought on production two wells in the Gulf of Mexico. The A-4 ST at Matterhorn began producing approximately 3,190 Boe per day net in mid-June and the A-13 at Mahogany began producing approximately 1,640 Boe per day net in late May. Also during the second quarter, we commenced drilling the A-5 ST well at Mahogany and are now currently completing the well. We expect to bring the A-5 ST online later this week with projected initial production rates of approximately 925 Boe per day net to W&T. Following the A-5 ST well at Mahogany we expect to drill the A-9 ST development well to further develop the P sand south of the A-5 ST during the third quarter. Following the A-9 ST well, we anticipate moving to another development drill well for a possible spud date in the fourth quarter followed by completion in early 2013. During the second quarter, we also commenced drilling the WC 73 #2 well. We have a 30% working interest in this non-operated well that targets the Cris R section at 18,100’ TVD. This well is expected to reach total depth during the third quarter.

We also anticipate commencing the drilling of three exploration wells in the Main Pass area with two in the third quarter and one in the fourth quarter. Our planned deepwater exploration well, where we have a 20% working interest, will most likely get started in the third or early fourth quarter of this year. We are waiting on final plans from the operator.

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Onshore

Wells Completed in Second Quarter 2012

Our Yellow Rose prospect is in the West Texas counties of Andrews, Martin, Dawson and Gaines. During the second quarter, we completed 15 wells in our Yellow Rose Field. In June, we commenced drilling our first horizontal test well targeting the Wolfcamp trend. The well was drilled with a 5,600’ lateral and we are currently conducting a 20 stage frac on this horizontal well. Current production from our Yellow Rose Field is approximately 3,200 Boe per day gross (2,465 Boe per day net) with seven wells awaiting completion. For the remainder of the year, we expect to continue our multi-rig program. Our rig line-up could change depending on our ultimate evaluation of our horizontal well program.

In Terry County, just north of our Yellow Rose prospect, we have an acreage position of approximately 9,500 acres. We are currently in the exploration and delineation phase of this prospect. During the second quarter we completed and began flowback on four vertical wells, bringing the total wells completed on this acreage to 14 vertical wells. The wells are in various stages of production and flowback. In the second half of 2012, we plan to drill two horizontal wells. After we evaluate the results of these wells, we expect to be able to provide our future development plans for this acreage.

In East Texas at our Star Prospect, we drilled and completed the Sinclair 399 #1 horizontal well and the well is currently in flowback. This well is part of a four well exploration program on our 143,000 net acres targeting the oil rich James Lime formation. We recently filed a permit to drill the Black Stone Colwell A-8

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in San Augustine County. The well is expected to TD at 9,000’ along with a lateral of around 6,200’. We will follow that well with a fourth well. We anticipate that the results of these four wells should provide sufficient data to delineate the project and determine future development plans. We have a 97% working interest in these wells and still estimate average well costs to run approximately $7.3 million, net. Our targeted initial production rates for these wells are 833 Boe per day. We reiterate that zero reserves have been booked for any of this acreage.

During the quarter we completed 7 workovers and 2 recompletes offshore and 56 workovers and 4 recompletes onshore. The combined cost was $8.7 million and initial production from the projects was 11.9 MMcfe per day or 2.0 MBoe per day. We continue to believe that these activities help maintain our production and maximize returns. We will continue with our recompletion program throughout the remainder of the year.

Outlook: The guidance for full year 2012 represents the Company’s best estimate of the range of likely future results, and is affected by the factors described below in “Forward-Looking Statements.” Our guidance for the full year 2012 is unchanged from our prior guidance and is shown in the table below. Production guidance includes the planned build up from our capital budget of $425.0 million for 2012.

Conference Call Information: W&T will hold a conference call to discuss financial and operational results on Tuesday, July 31, 2012, at 10:00 a.m. Eastern Time. To participate, dial (480) 629-9645 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 August 7, 2012, and may be accessed by calling (303) 590-3030 and using the pass code 4549376#.

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About W&T Offshore

W&T Offshore, Inc. is an independent oil and natural gas producer focused primarily in the Gulf of Mexico and Texas. We have grown through acquisitions, exploration and development and currently hold working interests in approximately 60 producing offshore fields in federal and state waters. During 2011, we expanded onshore into West Texas and East Texas where we are actively pursuing exploration and development activities. 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.

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, 2011 and subsequent Form 10-Q reports found at www.sec.gov or at our website at www.wtoffshore.com under the Investor Relations section.

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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 “Net Income Excluding Special Items,” “EBITDA” and “Adjusted EBITDA.” Adjusted EBITDA margin represents the ratio of Adjusted EBITDA to total revenues. 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 unrealized derivative (gain) loss, a litigation accrual, loss on extinguishment of debt, and associated tax effects. 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. Adjusted EBITDA excludes the unrealized gain or loss related to our derivative contracts, loss on extinguishment of debt, and a litigation accrual. 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. We believe this presentation is relevant and useful because it helps 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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