Press Release

Exhibit 99.1


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

W&T Offshore Reports a 44% Increase for Year-End 2011 Proved

Reserves over YE 2010 with a Reserve Replacement Ratio of 312% and a

63% increase in PV-10* of proved reserves for 2011 over 2010

The Company Also Announces a 37% Increase in its Capital Budget for 2012, Provides

2012 Production Growth Guidance and 2012 Reserve Goals, and Provides Operational

Update and CAPEX Details

HOUSTON – January 31, 2012 – W&T Offshore, Inc. (NYSE:WTI) reported that year-end 2011 proved reserves increased 44% to 116.9 million barrels of oil equivalent (“MMBoe”), which represents a reserve replacement ratio of 312% and an increase in PV-10 of proved reserves of 63%. It also announced that its Board of Directors approved the Company’s 2012 Capital Budget of $425 million, which is a 37% increase over 2011 and is anticipated to be funded with internally generated cash flow. The Company provided production guidance for 2012 to be in the range of 16.9 to 18.8 million barrels of oil equivalent (“MMBoe”) or 101.1 to 112.9 billion cubic feet equivalent (“Bcfe”). In regards to 2012 reserve growth, the Company’s goal is to increase reserves by at least 18% in 2012. In addition, the Company provided an operational update and details about its capital expenditure programs.

Year-End 2011 Proved Reserves are up 44% from YE 2010 (reserve replacement ratio of 312%) and PV-10 of Proved Reserves increased 63%.*

The Company’s year-end 2011 proved reserves increased 44% from year-end 2010 of 80.9 MMBoe as a result of acquisitions, extensions, discoveries and revisions, which represents a reserve replacement ratio of 312%. Estimated total proved reserves at December 31, 2011 consisted of 51.4 million barrels of oil, 720.1 million gallons of natural gas liquids (“NGLs”) and 289.7 Bcf of natural gas for a total of 116.9 MMBoe, or 701.1 Bcfe. Proved reserves were 59% oil and NGLs at year-end 2011, compared to 47% at year-end 2010. The present value of future

net revenues of our estimated total proved reserves, discounted at 10% (referred to as “PV-10”), was $3.1 billion at December 31, 2011 excluding the effect of estimated asset retirement obligations (“ARO”). PV-10 increased 63% from the PV-10 of our proved reserves at December 31, 2010 of $1.9 billion.

In accordance with guidelines established by the SEC, our proved reserves as of December 31, 2011 were determined to be economically producible under existing economic conditions, which requires the use of the unweighted arithmetic average of the first-day-of-the-month price for oil and gas for the period January 2011 through December 2011. Also note that the PV-10 value is a non-GAAP financial measure. See “Non-GAAP Financial Measure” below. For 2011, proved reserves and PV-10 were calculated using average prices of $97.36 per Bbl for oil, $1.22 per gallon for natural gas liquids and $4.11 per Mcf for natural gas, as adjusted for energy content for natural gas, quality, transportation fees and regional price differentials. The proved reserves and PV-10 for the 2010 period were calculated using average prices of $76.28 per Bbl for oil, $1.07 per gallon for natural gas liquids and $4.57 per Mcf for natural gas, as adjusted for energy content for natural gas, quality, transportation fees and regional price differentials.

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


	As of December 31, 2011
							Total Equivalent Reserves
	Oil		NGLs		Natural Gas		Barrel Equivalent		Natural Gas Equivalent		% of Total
Classification of Proved Reserves	(MMBbls)		(MMGals)		(Bcf)		(MMBoe) (1)		(Bcfe) (1)		Proved
Proved developed producing		17.9		347.3		169.4		54.4		326.3		46	%
Proved developed non-producing		5.6		117.5		82.1		22.1		132.4		19	%

Total proved developed		23.5		464.8		251.5		76.5		458.7		65	%
Proved undeveloped		27.9		255.3		38.2		40.4		242.4		35	%

Total proved		51.4		720.1		289.7		116.9		701.1		100	%

(1)	One Bcfe and one MMBoe are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). NGLs are converted to barrels using a ratio of 42 gallons to one barrel.

2012 Capital Budget

The 2012 capital budget is $425 million, which does not include acquisitions. This budget represents a 37% increase over the 2011 capital budget of $310 million. W&T anticipates fully funding the capital budget with internally generated cash flow. The 2012 Budget currently anticipates the drilling of 75 wells with $167 million (39%) for exploration activities (split 53% offshore and 47% onshore) and $258 million (61%) for development activities (split 63% offshore and 37% onshore). Details of the capital budget and estimated number of wells to be drilled, excluding acquisitions, are as follows ($ in millions):


	Estimated No. of Wells
Offshore -
Exploration Drill, Evaluate and Complete	6	$	88
Development Drill, Evaluate and Complete	4		121
Facilities, Recompletes, and Other			41

			250
Onshore -
Exploration Drill and Complete	19		79
Development Drill and Complete	46		91
Facilities			5

			175

Total	75	$	425

2012 Production Guidance and Reserve Goals

The Company expects to produce between 16.9 and 18.8 MMBoe or 101.1 and 112.9 Bcfe in 2012, consisting of approximately 47% crude oil and NGLs and 53% natural gas. Our estimated production for 2012 does not included any additional acquisitions but does reflect anticipated downtime from tropical storm activity consistent with our experience in 2011. It should be noted that the Company is currently receiving the Gulf Coast premium on approximately 84% of its oil production. In regards to proved reserves, the Company’s goal is at least 18% reserve growth in 2012 from December 31, 2011 as a result of drilling, acquisitions, extensions and revisions.

Operational Update and 2012 CAPEX Details

Offshore Gulf of Mexico

•

Gulf of Mexico Shelf: In the fourth quarter of 2011, we drilled four wells on the Gulf of Mexico Shelf, all of which were successful. We anticipate drilling eight wells on the Gulf of Mexico shelf in 2012. The following provides additional information regarding our recent and future activity on the Gulf of Mexico shelf :

•

Mahogany (WI 100%): We are currently drilling the A-13 well which is the third well of potentially a six well drilling program at the SS 349 field that commenced in 2011 and will continue into 2013. Thus far, we have completed two wells (the A-1 and A-11); both were drilled to ~14,500’ true vertical depth (“TVD”) targeting the P Sand (oil). Both wells were successful and are currently producing 2,100 Bbls per day and 7.6 MMcf per day net to our interest. The A-13 well is expected to add 1,500 Boe per day of net production in the third quarter.

•

South Timbalier 41 (WI 40%): The E-1 well was drilled to a measured depth of ~16,300’ and found gas pay in two sands. The well is currently producing 2.7 MMcf per day and 100 Bbls per day net to our interest.

•

South Timbalier 315 (WI 50%): The A-3 well was drilled to a total measured depth of ~13,000’ and found oil pay. The well is currently producing 170 Bbls per day and 240 Mcf per day net to our interest. This well is part of a broader work development program for the field with an expected increase in total production from the field of 380 Bbls per day and 570 Mcf per day.

•

MP 108 Field (WI 100%): The MP 108 #8 was hooked up and on line in December 2011 adding 5.9 MMcf per day and 170 Bbls per day net to our interest. The Company will soon complete its field study work and as a result, we expect to drill additional wells in late 2012 or early 2013.

•

The 2012 Budget includes five exploration wells on the shelf (average working interest of approximately 56%). The wells will be located in water depths of 33’ to 430’ targeting reservoirs from 9,000’ to 15,400’. The average cost of the wells to drill, complete and hook up is expected to be in the range of $15 million to $30 million gross, depending on our working interest.

•

Deepwater – GOM: In 2012, we plan to drill two wells in the deepwater of the Gulf of Mexico. The following provides additional information regarding our recent and future activity in the deepwater Gulf of Mexico:

•

Matterhorn (WI 100%): We are currently rigging up to drill the MC 243 A-4 ST well, which is a development well targeting oil sands. This well is expected to produce 3,500 Boe per of day net to our interest. The total estimated cost of the well is $47.6 million net.

•

Deepwater Well (WI 20%): This is an exploration well targeting oil in the deepwater. The well is expected to spud late in the second quarter of 2012 and we will provide additional details regarding the well in the near future.

•

Tahoe/SE Tahoe Fields (WI 70 - 100%): In late 2011, the Company installed a second compressor and modified the original compressor which has been reinstalled and is being tested. As a result of this compression project, we expect an increase in production of approximately 12 MMcfe per day gross starting in mid-February 2012.

Onshore

•

West Texas: We are actively exploring and developing in two distinct areas of West Texas. We will continue to pursue additional “bolt on” projects in the area.

•

Yellow Rose Project (WI 100%): This is a producing field that we acquired in May of 2011. Since May, we have drilled 28 wells and we exited 2011 producing 2,900 Boe per day. In 2012, we will continue with a 3 rig drilling program to

develop our Yellow Rose Project with approximately 50 vertical wells (drilled to TD of 11,000’ ) targeting about 4,500 feet of vertical section in the “Wolfberry” located on our 21,900 net acres in Dawson, Martin, Andrews and Gaines Counties. This development drilling program is expected to continue into 2015. The 2012 program includes drilling certain wells on 40-acre spacing versus the current 80-acre spacing, which is expected to increase proved reserves as well as production. At a cost of $2.0 million per well, we anticipate that each vertical well will yield a 26% IRR** using 163 MBoe per well estimated ultimate recovery (“EUR”) gross. The initial full month production rate is expected to be approximately 51 to 90 Boe per day gross. In mid-2012 we plan to begin our pilot test horizontal program with the drilling of a horizontal well in the field.

•

Terry County Prospects (WI 35.6-80%): We acquired 9,600 net acres of leasehold in late 2010 and 2011. The exploration wells targeted the Wolfberry at a depth of 12,000’ with an estimated cost of $2.3 million per well. In 2011, we drilled 12 exploration wells to test and evaluate prospects. Currently we are at various stages in the completions and flowbacks on those exploration wells. Although the results are encouraging, we are still within our exploration and delineation phase. We plan to continue to analyze the data received from those wells and will most likely drill a horizontal well in the prospects prior to announcing our future development plans.

**All

IRR calculations herein assume $90 per barrel flat oil pricing and $3 per Mcf flat natural gas pricing.

•

East Texas: To date, we have drilled two wells in two separate projects, both of which are still in completion and/or flowback stages.

•

Star Project (97% WI): The Company now controls 141,700 net acres located in five East Texas counties. In 2011, we drilled a horizontal exploration well to test and target the James Lime formation at approximately 8,000’ TVD. The well has been completed and is currently flowing back. This well is one of four exploration wells planned to delineate the project. In 2012 we anticipate drilling three additional horizontal wells which should provide sufficient data to determine future development plans. The estimated cost per well is $6.4 million, with a targeted IP rate of 833 Boe per day.

•

Branton East Prospect (35.4% WI): In 2011, we drilled and completed a vertical exploration well (16,800’ TVD) targeting the Cotton Valley. The initial production of the well has been delayed due to higher than expected H₂S content. Once this well has been fully tested we will report the results and any plans that we may have in the area.

•

Other Onshore Areas: In 2012, we will aggressively pursue additional high potential exploration projects that could yield large reserves and multi-year development programs which are included in the announced budget.

Tracy W. Krohn, Chairman and Chief Executive Officer, stated, “We are focused on growth at a profit which is supported by our reserve replacement ratio of 312% for 2011 and the 2012 guidance that is provided. We have increased our capital budget by 37% to fund a larger exploration and development drilling program. As outlined, the exploration activity comprises 39% of the total capital budget, while development activities (61%) serve to provide additional production and cash flow. The increase in our exploration efforts provides the Company more exposure to larger reserves and extended development programs. The budget does not include any 2012 acquisitions which appear very probable given the number of opportunities that we are seeing in the market. As discussed, we intend to increase both production and reserves in 2012 while delivering earnings to our shareholders.”

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 67 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 value of proved reserves before the effect of estimated ARO at December 31, 2011 is a non-GAAP financial measure. It differs from 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.

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