W&T Offshore Announces 2013 Capital Budget, Drilling Plans & 2013 Guidance And Provides Operations Update

W&T Offshore Announces 2013 Capital Budget, Drilling Plans & 2013 Guidance And
                          Provides Operations Update

Company announces positive results in its Yellow Rose drilling program

PR Newswire

HOUSTON, Feb. 12, 2013

HOUSTON, Feb. 12, 2013 /PRNewswire/ --W&T Offshore, Inc. (NYSE: WTI)
announced that its Board of Directors has approved a 2013 capital budget of
$450 million. The Company also announced production guidance for the first
quarter of 2013 in a range of 4.3 MMBoe to 4.8 MMBoe and for the full year of
2013 in a range of 17.0 MMBoe to 18.7 MMBoe. In addition, the Company
provided details about its capital expenditure programs and an operational
update, which includes positive results in both its horizontal drilling and
40-acre spacing pilot programs, adding value to its Yellow Rose project.

2013 Capital Budget

Approximately 63% of the $450 million capital budget for 2013 is identified as
exploratory drilling to drive organic growth of both reserves and production,
with the remaining 37% of the budget directed to oil-focused development
activities. We anticipate allocating 63% of the 2013 budget to projects in
the Gulf of Mexico, both on the shelf and in the deepwater, and 37% to
projects onshore in Texas.

Tracy W. Krohn, Chairman and Chief Executive Officer, stated, "In the past few
years we have added new exploration projects to support our goal of achieving
growth organically through the drill bit, as well as through acquisitions. In
2013 we are increasing our focus on exploration and building on recent
successes. We have great news with our Yellow Rose project as we are pleased
to report positive results in our horizontal drilling program in the
Wolfberry; positive results in our 40-acre spacing pilot program; and
production from the field is up 100% over last year at this time."

"Our 2013 capital budget of $450 million is designed with a balance of
offshore shelf, deepwater and onshore exploration drilling activity to drive
organic growth, plus a number of development projects focused on expanding our
oil production. As usual, our budget does not include acquisitions, but we
will continue to pursue acquisitions in this very active market to supplement
our expected organic growth. As in the past, we expect to continue to drill
within our cash flow."

Offshore Activity

We began 2013 with a high level of activity that was heavily weighted toward
exploration projects and currently have four rigs working in the Gulf of
Mexico. We believe our offshore exploration program offers solid
opportunities for organic reserve and production growth, as well as builds on
our recent successes.

At our highly successful "Mahogany" field, our fifth well in our multi-well
drilling program, the Ship Shoal ("SS") 349 A-9 development well was brought
on production in mid-January at an initial rate of approximately 2,700 Boe per
day from the P-sand, which has traditionally been the field's principal
productive reservoir. The A-9 well exceeded pre-drill expectations in our
main target. Additionally, it discovered another upside reservoir which was
also completed and will be retained as a future zone change, increasing total
proved reserves for the field. Current average daily gross production from
the Mahogany field is approximately 9,150 Boe (approximately 75% crude oil)
which is up from about 1,300 Boe per day gross in late 2011, an increase of
approximately 700% over the last 15 months.

On January 15, 2013, we spud the SS 349 A-14 well, the sixth well in our
multi-well drilling program at our Mahogany field, which is an exploration
well designed to test the T-sand, a deep play located beneath our main
reservoir. If successful, it will expand our proved reserves and possibly
create additional development opportunities in the field. The A-14 well also
holds proved reserves in the P-sand level, serving as a robust back-up to the
exploratory T-sand test. Following the SS 349 A-14 well, we plan to drill
the SS 349 A-15 well which is planned to target multiple stacked amplitudes in
the sub-salt section. The A-15 also has additional field expansion potential
in the P-sand and if successful will further expand the P-sand reservoir
limits. We continue to have excellent drilling results to date in this high
impact oil field and in the reserve and production expansion potential this
field has for the Company.

In addition, we are currently drilling two exploration wells in the Main Pass
("MP") Area. One is located in our MP 108 field, being the MP 108 B-1 well
targeting the Tex W-6 sand. We plan to drill another well, the MP 108 B-2
well, immediately following operations on the MP 108 B-1 well. We recently
drilled the MP 159 #1 well to TD but have deemed the well non-commercial. The
well is currently being plugged.

We anticipate drilling at least one additional deepwater exploration well in
2013, and will provide the details for that well in the future. We expect to
have additional capital expenditures in 2013 on our Mississippi Canyon ("MC")
698 "Big Bend" deepwater discovery that reached total depth in late 2012, once
it is sanctioned. Additionally we are currently evaluating the 65 deepwater
leasehold blocks we acquired in our Newfield property acquisition in the
fourth quarter of last year. As a result of the high level of interest in
those undeveloped leases, we are currently working on several joint venture

Our development activity in the Gulf of Mexico includes the MC 243
"Matterhorn" A-2 ST well which is currently drilling in the deepwater and
expected to add approximately 1,000 Boe per day production of initial rate.
We expect to follow this well with the planned MC 243 A-5 well, a water
injection well that will be used for pressure maintenance in the field. The
A-5 well is expected to increase the ultimate recovery of the eastern sector
of the field, add reserves and assuming success, would lead to additional
secondary reserves expansion in other areas of the field.

Other development wells on the 2013 schedule include the High Island 21 A-1
well targeting the LH-20 sand which will twin the previously producing High
Island 21 A-3 well. We also expect to finish the tie-back and hook up of the
West Cameron 73, a 2012 shelf discovery well with first production expected in
the third quarter of 2013.

The details of these offshore wells are outlined in the table below.

Wells Completed in the Fourth Quarter 2012
 Block/Well    WI%  Type Location  Target            Net     Comments
                                   Gas and                   facilities
 WC 73 #2      30   EXP  Shelf     condensate in     ~$13.2  installation.
                                   Cris R section at MM      Est. 1st
                                   ~18,100'                production - Q3
                                                             2013. Est IP:
                                                             ~380 Boepd net
Drilling Activity in the Fourth Quarter 2012
 Block/Well    WI%  Type Location  Target            Est.    Comments
                                                             Completed Jan 3,
                                                             discovered 2nd
                                                             pay zone adding
 SS 349 A-9    100  DEV  Shelf     Oil in P sand at  ~$27.2  to proved
 (Mahogany)                       ~14,300'         MM      reserves. 1st
                                                             production - Jan
                                                             2013. IP rate:
                                                             ~2,700 Boepd
                                                             Reached TD,
                                                             logged ~150 ft
 MC 698 #1                         Oil at ~15,300'   ~$20.2  oil pay in two
 (Big Bend)    20   EXP  Deepwater (Big Hum) sand    MM      high quality
                                                             Miocene sands.
                                                             Reached TD in
                                   Gas and liquids   ~$2.9   mid-Oct, deemed
 MP 163 #1     40   EXP  Shelf     at ~8,650'        MM      non-commercial,
Current Drilling Activity in the First Quarter 2013
 Block/Well    WI%  Type Location  Target            Est.    Comments
                                                             Drilling ahead.
                                                             Est. 1st
                                                             production - Q2
                                   Gas and liquids   ~$24.5  2013. Target IP:
 MP 108 B-1    100  EXP  Shelf     in Tex W 6 sand   MM      ~1,200 Boepd.
                                   at ~14,000' TVD           Unrisked
                                                             recovery: ~ 1.8
                                                             Rig on location
                                                             preparing to
                                   Proved oil                side-track at
 MC 243 A-2 ST 100  DEV  Deepwater reserves in the A ~$23.8  ~5,100'. Est.
 (Matterhorn)                      sand at ~6,800'   MM      1st production -
                                   TVD                       late Q1 2013.
                                                             Target IP: ~1,000
                                   Oil at ~17,200'           Drilling ahead.
                                   TVD in the T2             Est. 1st
                                   sand (exploration         production - late
 SS 349 A-14                       target).                 Q2 2013. Est. IP
 (Mahogany)    100  EXP  Shelf     Secondary target  ~$39 MM rate: ~2,000
                                   in the P sand             Boepd. Unrisked
                                   (development) at          anticipated
                                   ~14,200' TVD              recovery: ~ 3.1
                                                             Drilling rig on
                                   Gas and liquids   ~$6.6   location. Deemed
 MP 159 #1     100  EXP  Shelf     ~7,400' in the    MM      non-commercial,
                                   UVIG-3 sand               currently being
Upcoming Drilling Activity in 2013
 Block/Well    WI%  Type Location  Target            Est.    Comments
                                                             Projected spud
                                                             date - Q2 2013,
                                                             Est 1st
                                   Gas and liquids           production - Q3
 MP 108 B-2    100  EXP  Shelf     in Tex W 6 sand   ~$24.1  2013, Target IP:
                                   at ~14,000' TVD   MM      ~1,200 Boepd.
                                                             recovery ~ 1.7
                                   Water injection           Projected spud
 MC 243 A-5    100  DEV  Deepwater well for          ~$28.6  date - Q2 2013.
 (Matterhorn)                      increased         MM      Est. project
                                   reserves (oil)            online - Q3 2013.
                                                             Projected spud
                                                             date - mid 2013.
                                   Multiple                  Est. 2st
                                   exploratory               production - Q4
 SS 349 A-15   100  EXP  Shelf     targets (N, O, P, ~$35 MM 2013. Target IP:
 (Mahogany)                        Q, Q5 sands) ~            ~1,500 Boepd.
                                   14,000'-14,500'           Unrisked
                                   TVD                       anticipated
                                                             recovery ~ 4
                                                             Projected spud
                                                             date Q1 '13.
                                   LH20 sands; low          Est. 1st
                                   risk gas                  production: Q3
 HI 21 A-1     100  DEV  Shelf     development       ~$25 MM 2013. Target IP:
                                   extension @ ~             ~1,500 Boepd.
                                   12,500'                   Unrisked
                                                             recovery: ~ 3.2

Onshore Operations Update:

Onshore, as a result of our success with both the Wolfcamp horizontal drilling
program and the 40-acre infill spacing, we have added value to our Yellow Rose
project in the Permian Basin (Martin, Dawson, Gaines and Andrews counties).
Our 2013 budget provides for the drilling of seven horizontal and 20 vertical
wells and we currently have two rigs running in the field.

During the fourth quarter of 2012, we completed 18 new wells at our Yellow
Rose project, bringing the total completed wells for 2012 to 64 wells. During
2012, W&T focused on three specific areas to add value to our Yellow Rose
Wolfberry development, which were: (1) enhanced 80 acre vertical development
drilling program, (2) down-spaced pilot program to 40 acre spacing vertical
development, and (3) exploring our horizontal development potential in the
Wolfcamp. Tactically we have focused on field optimization, as well as on
continuous and aggressive stimulation development and deployment in our
vertical and horizontal campaigns. Current production rate for our Yellow
Rose project is approximately 5,150 Boe per day gross which is 100% above
field production rates a year ago. This production performance improvement is
driven by several factors including attractive vertical well completion
performance, continued improvements in our field uptime and effectiveness,
attractive results from our 40-acre infill program and, most recently,
encouraging results from our new Wolfcamp horizontal wells.

Our more recent vertical wells have seen improved initial production rates
with our latest wells averaging approximately 67 Boe per day (average 30 day
production rate) as we continue to refine our fracture stimulation program,
with vertical well costs averaging approximately $ 2.3 million. Prior to year
end 2012, the company carried no "proved" reserves associated with down-spaced
40 acre locations. A portion of our 2012 drilling capital was aimed at infill
drilling specific pilot areas to 40 acre vertical well spacing and we had good
success with the down-spacing program, observing positive incremental
production and incremental reserves in our 40 acre pilot areas. At year end,
we began booking a portion of our 40 acre infill locations into "proved" and
expect that trend to continue into 2013, 2014 and beyond. Should we be able
to fully develop our acreage on 40 acre locations, the company would possess a
total of 200 to 300 40-acre locations across our Yellow Rose project.

Complementing our vertical development, during 2012 we drilled and brought on
line two new horizontal Wolfcamp wells, with one well achieving an initial
production ("IP") rate of 485 Boe per day and another well achieving 346 Boe
per day. W&T's longest Wolfcamp horizontal has been a 7,482' lateral with a
23 stage frac treatment. Our most recent horizontal well, currently on
flowback, has just been stimulated with a 28 stage frac treatment. We are
pleased with our initial horizontal well results and our leading completion
practices in this emerging play. As a result of our successful horizontal
exploration tests of the Wolfcamp formation, we have budgeted to drill and
complete seven horizontal Wolfcamp wells for 2013. These wells are designed
to have an average lateral length of 5,400 feet completed with between 20 and
22 hydraulic fracturing stages at a total well cost of approximately $ 6.0
million to $7.0 million, depending on the length of the lateral. Based on our
early evaluation of the program, we expect IP rates of 350 to 400 Boe per day
and estimated ultimate recoveries ("EUR") of 300 to 450 MBoe, also depending
on the length of the lateral. Assuming continued success with this program,
we anticipate expanding our horizontal operations in the Wolfcamp formation
and potentially testing additional horizontal levels (benches) in other
formations on our acreage position. Ultimately, we may consider further
vertical well down spacing to 20-acre spacing or even less, adding even
greater development potential for our acreage position.

In Terry County, West Texas, our horizontal drilling program is progressing
with two wells fracture stimulated and on flowback. To date, we do not have
enough information on the flowbacks to determine our future development
plans. We anticipate having more information within the next few months.

In East Texas at our Star Prospect, we have completed drilling and fracture
stimulation of the third and fourth wells of our initial delineation program.
Both of those wells are now on flowback, and we should be able to determine
our future plans on this project in the near term.

The details of our onshore wells are outlined in the table below.

Wells Completed in Fourth Quarter 2012
 Project & Area WI%   Type   # of   Target        Net     Comments
                              Wells                 Cost
Permian Basin
 Yellow Rose    100   EXP     1      Horizontal     ~$5.1   IP rate: 485 Boepd
 Pinotage 8H                        Wolfcamp     MM      (gross)
                                                            30 Day Avg: 309
                                                            Boepd (gross)
                                     4,500'                 Drilled on 40 acre
 Yellow Rose   90    EXP     1      vertical       ~$2.0   spacing, on
                                     section in the MM      production
                                     4,500'         ~$2 MM  Drilled on 80 acre
 Yellow Rose   100   DEV     16     vertical       per     spacing, on
                                     section in the well    production
 Terry County                        Horizontal     ~$6.6   Completed, on
 State Travis   90    EXP     1      Wolfcamp     MM      flowback
 Henson #1H
 Terry County                        Horizontal     ~$5.9   Completed, on
 Holmes 23-4    90    EXP     1      Wolfcamp     MM      flowback
East Texas
                                                            3rd well of 4 well
 Star Prospect  97    EXP     1      James Lime     ~$7.3   delineation
 Colwell A8 #1H                      Horizontal     MM      program - on
 Star Prospect                                              4th well of 4 well
 McMahon A-28   97    EXP     1      James Lime     ~$7.6   delineation
 #1H                                 Horizontal     MM      program - on
Drilling Activity in the Fourth Quarter 2012
                              # of                  Net
 Project & Area WI%   Type   Wells  Target        Est.    Comments
Permian Basin
                                     4,500'         ~$2.3   Reached TD, 10
 Yellow Rose   100   DEV     12     vertical       MM per  awaiting
                                     section in the well    completion, 2 on
                                     Wolfberry              flowback
                                                            Recently completed
                                                            and currently
 Yellow Rose                         Horizontal     ~$7.4   producing
 Chablis #5H    100   EXP     1      Wolfcamp     MM      IP rate: 346 Boepd
                                                            30 Day Avg: N/A
                                                            too early
 Yellow Rose                                                28 Stage Frac
 UL 6-23 Unit   100   EXP     1      Horizontal     ~$6.8   treatment in
 2H                                  Wolfcamp     MM      Feb.; Well on
Current Drilling Activity in the First Quarter 2013
                              # of                  Net
 Project & Area WI%   Type   Wells  Target        Est.    Comments
Permian Basin
                                     4,500'         ~$2.3   Drilling, single
 Yellow Rose   100   DEV     2      vertical       MM per  vertical rig
                                     section in the well    program
Upcoming Drilling Activity in 2013
                              # of                  Net
 Project & Area WI%   Type   Wells  Target        Est.    Comments
Permian Basin
                                     4,500'         ~$2.3   Single rig program
 Yellow Rose   100   DEV     ~20   vertical       MM per  underway for
                                     section in the well    vertical wells.
                                                    ~$6.0   Single rig program
 Yellow Rose   100   EXP     ~7    Horizontal     MM to   underway for
                                     Wolfcamp     $7.0 MM horizontal
 Yellow Rose Horizontal Wells - Avg days to drill: 39 days, Days to 1st
 production: 90 days, Est. Gross EUR: ~300-450 Mboe (oil plus wet gas, no
 NGLs), Est. IP: 350-400 Boepd gross
 Yellow Rose Vertical Wells - Avg days to drill: 18 days, Days to 1st
 production: 60 days, Est. Gross EUR: ~119 Mboe (oil plus wet gas, no NGLs),
 Est. IP: ~ 67 Bopd gross

2013 Outlook:

Our guidance for the first quarter and full year 2013 is provided in the table
below and represents the Company's best estimate of the range of likely future
results. Our results may be affected by the factors described below in
"Forward-Looking Statements." Our expected results for the full year 2012 are
unchanged from our prior guidance last provided on November 28, 2012.

                                 First Quarter         Full-Year
 Estimated Production
                                 2013                  2013
Oil and NGLs (MMBbls)            2.0– 2.2             8.1–9.0
Natural gas (Bcf)                14.2 –15.7           52.9 – 58.5
Total (Bcfe)                     26.0 – 28.7           102.0 – 112.0
Total (MMBoe)                    4.3 – 4.8             17.0 – 18.7
Operating Expenses               First Quarter         Full-Year
 ($ in millions)
                                 2013                  2013
Lease operating expenses         $55.7 – $61.5         $221 – $244
Gathering, transportation &   $7.7 – $8.5           $37 – $41
production taxes
General and administrative       $22.3 – $24.7         $78 – $86
Income tax rate (1)              36%                   36%
(1) For income statement purposes only and not a reflection of estimated tax
payments or refunds in 2013.

Derivative Schedule Update:

W&T has posted an update to its commodity derivatives schedule provided in the
investor relations section of its website that includes all of our most recent
changes to our derivatives positions. Investors may also visit the website to
sign up to receive alerts of updates to our commodity derivative positions

About W&T Offshore

W&T Offshore, Inc. is an independent oil and natural gas producer with
operations offshore in the Gulf of Mexico and onshore in both the Permian
Basin of West Texas and in East Texas. We have grown through acquisitions,
exploration and development and currently hold working interests in
approximately 72 offshore fields in federal and state waters (69 producing and
three fields capable of producing). W&T currently has over 1.4 million gross
acres under lease including over 710,000 gross acres on the Gulf of Mexico
Shelf, over 480,000 gross acres in the deepwater and over 221,000 gross acres
onshore in Texas. 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.

We may use the terms "potential reserves," "targeted reserves," "unrisked
anticipated recovery", "ultimate recovery" and "EUR" to describe estimates of
potentially recoverable hydrocarbons that the SEC rules strictly prohibit us
from including filings with the SEC. These are the Company's internal
estimates of hydrocarbon quantities that may be potentially discovered through
exploratory drilling or recovered with additional drilling or recovery
techniques. These quantities may not constitute "reserves" within the meaning
of the Society of Petroleum Engineer's Petroleum Resource Management System or
SEC rules and do not include any proved reserves. EUR estimates and drilling
locations have not been risked by Company management except where indicated.
Actual locations drilled, and quantities that may be ultimately recovered from
the Company's interests could differ substantially from the Company's
estimates. There is no commitment by the Company to drill all of the drilling
locations which have been attributed to these quantities. Factors affecting
ultimate recovery include the scope of our ongoing drilling program, which
will be directly affected by the availability of capital, drilling and
production costs, availability of drilling services and equipment, drilling
results, lease expirations, transportation constraints, regulatory approvals
and other factors; and actual drilling results, including geological and
mechanical factors affecting recovery rates. Estimates of targeted reserves,
potential reserves and average well EUR may change significantly as
development of the Company's oil and gas assets provide additional data.

Our production forecasts, estimated initial production rates and expectations
for future periods are dependent upon many assumptions, including estimates of
production decline rates from existing wells and the undertaking and outcome
of future drilling activity, which may be affected by significant commodity
price declines or drilling cost increases.

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

SOURCE W&T Offshore, Inc.

Website: http://www.wtoffshore.com
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