W&T Offshore Reports Second Quarter 2013 Financial and Operational Results

  W&T Offshore Reports Second Quarter 2013 Financial and Operational Results

PR Newswire

HOUSTON, Aug. 7, 2013

HOUSTON, Aug. 7, 2013 /PRNewswire/ --W&T Offshore, Inc. (NYSE: WTI) today
announced financial and operational results for the second quarter of 2013.
Some of the highlights include: 

  oProduction volumes averaged 45.3 MBoe per day, or 271.8 MMcfe per day
    during the second quarter of 2013. Approximately 3.2 Bcfe of production
    was deferred due to operational issues during the quarter. We estimate
    that we are currently capable of producing approximately 330 MMcfe per day
    when these operational issues are resolved.
  oOil production for the second quarter of 2013 increased 14.2% over the
    second quarter of 2012. Production volumes were split 40% oil, 12% NGLs
    and 48% natural gas.
  oAverage realized sales price was $101.78 per barrel for oil, $32.17 per
    barrel for NGLs and $4.22 per Mcf for natural gas.
  oAfter the quarter end, we brought on line the Ship Shoal 349 "Mahogany"
    A-14 well, which has reached a peak rate so far of 3,588 barrels of oil
    per day and 6.3 MMcf of gas per day, for a total of approximately 4,644
    Boe per day gross (3,870 Boe per day net to W&T after royalties).
  oRevenues were $235.4 million, net income was $22.4 million and earnings
    per share were $0.29.
  oAdjusted EBITDA was $142.8 million, up $8.0 million over the second
    quarter of last year, and Adjusted EBITDA Margin was 61%.
  oNet cash provided by operating activities for the first half of 2013 was
    $297.4 million, up from $241.3 million for the comparable 2012 period.
  oCompleted one offshore well during the quarter and, as of June 30^th, four
    additional offshore wells were actively drilling or in completion phase.
  oCompleted nine onshore wells in the Permian Basin of West Texas (two
    horizontal and seven vertical) during the quarter and two additional wells
    (one horizontal and one vertical) during July.
  oIn June, we announced our participation in a new deepwater prospect,
    "Troubadour", in Mississippi Canyon 699, which is currently drilling in
    the block adjacent to our 2012 discovery, MC 698 "Big Bend".
  oPaid a dividend of $0.09 per share during the quarter.
  oOn August 1, 2013, we received tax refunds totaling approximately $54
    million.

Tracy W. Krohn, W&T Offshore's Chairman and Chief Executive Officer, stated,
"2013 is developing into another successful year with the drill bit for W&T,
which includes multiple discovery wells that are expected to add substantial
new reserves and further our efforts for organic growth. Year to date, we
have drilled six successful wells offshore in the Gulf of Mexico and have
additional exploratory wells underway. Our Mahogany field is expanding with
each exploratory well, as we continue to add high quality oil sands which have
not previously been discovered. We will continue to explore within this field
as the reservoir limits have not yet been determined.

"In addition to our other recent discoveries, we are participating in the
drilling of another deepwater exploration well at 'Troubadour', being
Mississippi Canyon 699, located in the deepwater adjacent to our successful
discovery 'Big Bend' at Mississippi Canyon 698. Assuming success, Troubadour
would most likely be co-developed with Big Bend, adding considerable future
production and reserves.

"Onshore in West Texas at our Yellow Rose field we continue to increase our
initial production (IP) rates and expand the estimated ultimate recoveries
(EURs) in our vertical wells. Our average daily production is up nearly 15%
since the fourth quarter of 2012. We recently added 2,160 net acres to our
Yellow Rose position, bringing our total net acreage to 25,730 acres. This
new acreage provides us with even more opportunities for production and
reserve growth."

Revenues, Production, and Price: Revenues for the second quarter were $235.4
million compared to $215.5 million in the second quarter of 2012. Overall,
revenues increased due to a 16.8% rise in average commodity prices, which was
slightly offset by a 6.8% decrease in total production for the second
quarter. During the second quarter of 2013, we sold 1.7 million barrels of
oil, 0.5 million barrels of natural gas liquids (NGLs) and 11.8 billion cubic
feet (Bcf) of natural gas as compared to 1.5 million barrels of oil, 0.6
million barrels of NGLs and 14.3 Bcf of natural gas for the same period of
2012. In total, we sold 4.1 million barrels of oil equivalent (Boe) at an
average realized sales price of $56.88 per Boe compared to 4.4 million Boe
sold at an average realized sales price of $48.71 per Boe in the second
quarter of 2012. Oil revenues were higher due to a 14.2% increase in sales
volumes, which was partially offset by a slight decrease in prices. NGL
revenue declined due to lower prices and lower sales volumes. Natural gas
revenues were higher due to a 69.5% increase in prices, which were partially
offset by a 17.3% decrease is sales volumes. 

Production for the second quarter of 2013 was affected throughout the quarter
by downtime at up to 10 different fields and or platforms for a number of
reasons including third party pipeline outages and platform maintenance, as
well as certain well performance issues. We estimate we have had between 30
MMcfe/day and 90 MMcfe/day of our production shut in during portions of April,
May and June as a result of these issues, which include the
following:production at Mississippi Canyon 506 "Wrigley" continues to be
deferred as a result of maintenance at Shell's Cognac platform and related
pipelines;production was shut in at our East Cameron 321 platform for water
treating upgrades and oil and gas pipeline issues, and two wells in our
Fairway field are shut in awaiting workovers; and third party oil sales
pipelines were shut in at Mississippi Canyon 800 "Gladden" and Ship Shoal 349
"Mahogany" at various times during the quarter. Total deferred production for
the second quarter was approximately 3.2 Bcfe.

Adding back our volumes related to downtime, production for the quarter would
have averaged roughly 307.8 MMcfe per day. From a commodity standpoint,
roughly 70% of the deferred volumes during the second quarter were gas
related. This operationally deferred production is now reflected in our
revised production guidance provided later in this news release. Our guidance
also reflects 2.5 Bcfe of potential downtime for tropical storms, but does not
account for any volumes related to potential acquisitions or divestitures.
The current realized net production rate for early August is approximately 295
Mcfe per day, with a total company production capacity in excess of 330 Mcfe
per day (including temporary shut in production expected to resume in the
short term).

Net Income & EPS: Second quarter of 2013 net income was $22.4 million, or
$0.29 per common share, compared to net income of $53.6 million, or $0.70 per
common share for the same period in 2012. Net income for the second quarter
of 2013, adjusted to exclude special items, was $15.3 million, or $0.20 per
common share. This compares to $21.0 million, or $0.28 per common share for
the second quarter of 2012. 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 news 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 at the back of this news release.  Adjusted EBITDA for the
second quarter of 2013 was $142.8 million, up from $134.9 million for the same
period in 2012, due to higher oil production volumes and higher natural gas
prices. Net cash provided by operating activities for the first half of
2013 was $297.4 million, compared to $241.3 million for the same period of the
prior year. In August 2013, we received tax refunds totaling approximately
$54 million from the U.S. Treasury in connection with federal net operating
loss carrybacks to 2010 and 2011. 

As of June 30, 2013, we have spent $44.5 million and expect to incur an
additional $2.6 million for removal of wreckage associated with platforms
damaged by Hurricane Ike.In connection with our litigation with our excess
insurance underwriters, on July 31, 2013, the Court ruled in favor of the
underwriters, adopting their position that the excess policies cover removal
of wreck and debris claims only to the extent the limits of our Energy Package
policies have been exhausted with removal of wreck and debris claims. We
disagree with the Court's ruling and intend to appeal the decision.

Lease Operating Expenses (LOE): Lease operating expenses, which include base
lease operating expenses, insurance premiums, workovers and maintenance on our
facilities, increased $8.0 million to $68.2 million in the second quarter of
2013 compared to the second quarter of 2012. On a component basis, all costs
were lower except workover expense which increased $11.4 million primarily as
a result of a rig workover on a well at our Main Pass 69 field, which we
expect to return to production during the fourth quarter of this year.

Depreciation, Depletion, Amortization, and Accretion (DD&A): DD&A, including
accretion for ARO, increased to $4.04 per Mcfe for the second quarter of 2013
from $3.24 per Mcfe in the prior year period. On a nominal basis, DD&A
increased to $99.9 million for the second quarter of 2013 from $85.9 million
in the prior-year period. DD&A on a per Mcfe basis and nominal basis
increased primarily due to costs capitalized to the full cost pool from both
the unevaluated pool and from increases in our ARO estimates without a
corresponding increase in proved reserves, which primarily occurred in the
latter part of 2012. In addition, we incurred development costs during 2012
and the first half of 2013 above previous estimates, and as a result, we
increased our estimates of future development costs. The Newfield properties
acquired in 2012 also increased the DD&A rate on a per Mcfe basis.

General and Administrative Expenses (G&A): G&A increased to $19.9 million for
the second quarter of 2013 from $14.6 million for the prior-year period
primarily due to increases in accrued goal-based incentive compensation,
timing of surety premiums associated with supplemental bonding, consulting
services related to drilling operations, and lower overhead billed to joint
interest partners. The second quarter of 2012 reflected no accrual for
cash-based incentive compensation.

Derivatives: For the second quarter of 2013 and 2012, our derivative net
gains were $12.8 million and $49.9 million, respectively, and relate to the
change in the fair value of our crude oil commodity derivatives as a result of
changes in crude oil prices. Although the contracts relate to production for
the current year and next year, changes in the fair value for all open
contracts are recorded currently. For the second quarter of 2013, the net
gain was composed of a $1.9 million realized and a $10.9 million unrealized
gain. For the second quarter of 2012, the net gain consisted of a realized
loss of $0.3 million and an unrealized gain of $50.2 million. We have posted
an update to our commodity derivatives schedule in the investor relations
section of our website at http://www.wtoffshore.com.

Interest Expense: Interest expense incurred increased to $21.5 million for
the second quarter of 2013 from $14.7 million for the prior-year period. The
aggregate principal amount of our 8.50% Senior Notes outstanding was $900.0
million in the second quarter of 2013, compared to $600.0 million in the
prior-year period due to the issuance of 8.50% Senior Notes during October
2012. During the second quarter of 2013 and 2012, $2.5 million and $3.3
million, respectively, of interest was capitalized to unevaluated oil and
natural gas properties. The decrease is primarily attributable to
reclassifying various unevaluated properties to the full cost pool during the
fourth quarter of 2012.

Income Taxes: Income tax expense declined to $12.4 million for the second
quarter of 2013, compared to $34.2 million for the same period of 2012,
primarily due to lower pre-tax income. Our effective tax rate for the three
months ended June 30, 2013 was 35.7% and differed from the federal statutory
rate of 35.0% primarily as a result of state income taxes. Our effective tax
rate for the second quarter of 2012 was 38.9% and differed from the federal
statutory rate primarily as a result of the recapture of deductions for
qualified domestic production activities under Section 199 of the IRC as a
result of loss carrybacks to prior years.

Capital Expenditures: Our capital expenditures for the first six months of
2013 were $299.2 million. Capital expenditures were composed of $109.3
million for exploration activities, $168.1 million for development activities,
and $21.8 million for leasehold and other costs.  Offshore activities
accounted for 64% of the capital expenditures with 36% allocated to onshore
activities.

Operations Review and Update

OFFSHORE

Offshore Wells Completed in the Second Quarter 2013
 Block/Well      WI%  Type Location  Target                  Comments
 MC 243 A-2 ST                       Proved oil reserves in  Currently
 (Matterhorn)    100  DEV  Deepwater the A sand at ~6,800'   producing.
                                     TVD
Current Offshore Drilling Activity in the Third Quarter 2013
 Block/Well      WI%  Type Location  Target                  Comments
                                     Oil at ~17,200' TVD in
                                     the T2 sand
 SS 349 A-14                         (exploration target).  Currently
 (Mahogany)      100  EXPL Shelf     Secondary target in     producing.
                                     the P sand
                                     (development) at
                                     ~14,200' TVD
                                     Gas and liquids in Tex  Well is completed
 MP 108 B-1      100  EXPL Shelf     W 6 sand at ~14,000'    and awaiting
                                     TVD                     final hook-up.
                                                             Well has reached
 MC 243 A-5                          Water injection well    TD and is
 (Matterhorn)    100  EXPL Deepwater for increased reserves  currently
                                     (oil)                   awaiting
                                                             completion.
 HI 21 A-1                           Gas and liquids at      Well has reached
 (High Island 22 100  DEV  Shelf     ~12,500' in the LH-20   TD and is
 field)                              sand                    currently being
                                                             completed.
                                     Exploration prospect    Currently
 MC 699                              in the block adjacent   drilling. Well
 (Troubadour)    20   EXPL Deepwater to MC 698 "Big Bend"    projected to
                                     discovery              reach TD within
                                                             the week.
Upcoming Offshore Drilling Activity in 2013
 Block/Well      WI%  Type Location  Target                  Comments
                                     Multiple exploratory
 SS 349 A-15     100  EXPL Shelf     oil targets (N, O, P,   Projected spud
 (Mahogany)                          Q, Q5 sands) at         date - Q3 2013.
                                     13,000' to 15,500' TVD
                                     Targeting new oil       Projected spud
 EC 321 A-2 ST   100  EXPL Shelf     reserves in the Lentic  date - Q3 2013.
                                     1 sand at ~8,500 ' TVD

OFFSHORE EXPLORATION AND DEVELOPMENT

Deepwater Gulf of Mexico
Capitalizing on the late 2012 discovery at Mississippi Canyon 698, Big Bend,
we have acquired a 20% working interest in the Noble-operated Troubadour well
in Mississippi Canyon 699. Drilling operations are currently underway at
Troubadour, and we expect the well to reach total depth (TD) in the next few
days. Assuming success, we would expect that Troubadour would be co-developed
with Big Bend, adding production and reserves.

Ship Shoal 349 "Mahogany" Field
During July we made a deep shelf subsalt discovery in the T-sand in our Ship
Shoal 349 Mahogany field. The SS 359 A-14 well exceeded our pre-drill
expectations reaching a peak production rate from the T-Sand (in excess of
17,200' total vertical depth) of 3,588 barrels of oil per day and 6.3 MMcf of
gas per day, for a total of approximately 4,644 Boe per day gross (3,870 Boe
per day net to W&T after royalties). The T-Sand is the deepest sand
discovered in this field, as there is additional pay identified in the M-Sand,
N-Sand, and O-Sand, all of which represent future reserve additions to the
Company. The well also penetrated a thicker-than-expected P-sand interval
(the main field pay sand) which will also serve as a future recompletion. In
total, the A-14 well logged over 370 feet of net oil pay, with the T-Sand
accounting for 108 feet of the total net pay. This new discovery is expected
to stimulate additional drilling in 2014 to exploit all of these oil sands
encountered in the A-14 well.

The platform rig at Mahogany is currently working on a major recompletion in
the A-4 well, designed to bring a behind pipe P-Sand interval into production
at an expected rate of 1,000 Boe per day net to W&T after royalties with an
anticipated production date of August or September. Following the A-4
recompletion we expect to spud the A-15, a deep shelf subsalt exploratory
well, which targets oil sands in multiple horizons. The A-15 well is
scheduled to reach TD near the end of 2013 or early 2014 with a target IP rate
of 1,390 Boe per day net to W&T after royalties. The target reserve potential
associated with the A-15 well is anticipated to be in the range of 1.8 to 6.2
million Boe.

Our sub-salt Mahogany oil field continues to expand in both the aerial
footprint as well as in vertical column and number of productive sand
intervals. With the Mahogany field's existing infrastructure, our new
extension reserve additions are particularly impactful from a value
perspective with our ability to rapidly bring new production on stream and
quickly monetize new reserves.

Main Pass 108 Field
At our Main Pass 108 field, we recently completed the B-1 ST well which is in
the final stages of pre-production hookup. The well encountered our objective
sand, the Tex W-6 (73' of measured depth net pay), and logged additional pay
(30' of measured depth net pay) in the Tex W-3 sand. Initial production is
expected in August at a rate of 950 Boepd net. The well will result in new
reserve bookings in both the Tex W-6 primary zone as well as the secondary
sand, the Tex W-3.

Mississippi Canyon 243 "Matterhorn" Field
During the second quarter we began producing the Mississippi Canyon 243 A-2
side track and commenced operations on the A-5 well to drill a side track for
a pressure maintenance project. We recently reached TD, and logged
approximately 220 feet of net pay in the well exceeding pre-drill expectations
with one of the thickest A-sand intervals in the field. We currently plan to
produce the A-5 for a period of time before conversion to water injection for
field pressure maintenance. We plan to commence completion operations in
September with anticipated first production early in the fourth quarter of
2013.

High Island 22 Field
In early July we reached TD at our High Island 21 A-1 development well. The
well encountered the main pay sands largely as expected and in addition has
penetrated additional upside pay zones above the main pay that will serve as
future recompletion intervals. One of these zones, the LH16 will also result
in additional reserve bookings. Completion operations are currently underway,
with first production expected in either the late third quarter or early
fourth quarter of 2013. The target initial production rate is approximately
1,500 Boe per day net to W&T after royalties.

East Cameron 321 Field
We will mobilize a rig in September to our East Cameron 321 platform to begin
drilling the A-2 ST exploratory well. Our current project timeline has the
well coming online with initial production in October 2013. The target
initial production rate is approximately 850 Boe per day net to W&T after
royalties. EC 321 has been a historically significant oil producing field,
and this project has a target reserve potential of 1.1 MMBoe.

ONSHORE

Onshore Wells Completed in Second Quarter 2013
 Project & Area WI% Type # of Wells  Target               Comments
Permian Basin
 Yellow Rose                          Horizontal Wolfcamp   1 well on
 Horizontal     100 DEV   2           "A"                 flowback, 1 well
                                                            on production
 Yellow Rose                          4,500' vertical       Wells on
 80 Acre        100 DEV   6           section in the        production
 Verticals                            Wolfberry
 Yellow Rose                          4,500' vertical
 40 Acre        100 EXP   1           section in the        Well on production
 Verticals                            Wolfberry
Onshore Wells Completed in the Third Quarter 2013
 Project & Area WI% Type # of Wells  Target               Comments
Permian Basin
 Yellow Rose    100 DEV   1           Horizontal Wolfcamp   Well on production
 Horizontal                           "A"
 Yellow Rose                          4,500' vertical
 80 Acre        100 DEV   1           section in the        Well on production
 Verticals                            Wolfberry

 Yellow Rose Horizontal Wells - Targeted "all-in" well cost: $6 - $7 million,
 Avg days to drill: 39 days, Days to 1st production: 90 days, Targeted gross
 expected ultimate recovery ("EUR"): ~300-450 Mboe, Targeted initial
 production ("IP"): 350-400 Boepd gross (EURs and IP rates are oil plus wet
 gas, does not include NGL uptick), and all other costs attributable to well
 to achieve first production.
 Yellow Rose Vertical Wells - Targeted "all-in" well cost: $2.0 - $2.3
 million, Avg days to drill: 18 days, Days to 1st production: 60 days,
 Targeted gross EUR: ~130 Mboe, Targeted IP: 100 Boepd gross (EURs and IP
 rates are oil plus wet gas, does not include NGL uptick), and all other costs
 attributable to well to achieve first production.



ONSHORE EXPLORATION AND DEVELOPMENT

Yellow Rose Project
We are continuing our current two-rig drilling program at Yellow Rose and have
completed nine wells (two horizontal wells and seven vertical wells) during
the second quarter. We completed two additional wells, one horizontal and one
vertical, during July. The June exit rate at Yellow Rose was approximately
3,989 net Boe per day. During July, the field hit a new peak production high
of 4,387 net Boe per day. The field has continued to see increases in the
average 30-day peak production rate as more high-quality vertical wells are
brought online. We have continued to drill additional wells on 40-acre
spacing during the quarter and our current results are consistent with the
type curves seen in the offset 80-acre wells on our Yellow Rose acreage adding
additional momentum for our down-spacing infill program. We have booked
reserves for approximately fifty PUD locations on 40-acre spacing, which
represents only a small percentage of our total potential 40-acre down-spacing
well locations. Further upside for the company exists when we move towards 20
acre vertical spacing tests which will be a consideration for 2014 capital.

Having completed six horizontal wells in the Yellow Rose area, we are in the
early stages of our horizontal well program. We continue to refine target
depths, optimize our specific completion techniques and lateral lengths, and
evaluate early time production trends in all our wells. We have had varying
results in our horizontal program with current efforts limited to the Wolfcamp
A formation. During the third quarter of 2013, we plan to spud our first
Wolfcamp B horizontal well. Early indications and petrophysical analysis
suggest equivalent production potential from this interval compared to other
known Wolfcamp B production elsewhere in the basin and we look forward to
testing this new formation with preliminary Wolfcamp B results expected before
year end 2013. Additionally, the company is aggressively evaluating other
zones equally attractive for potential horizontal exploitation, such as the
Spraberry, additional Wolfcamp members, the Cline and other zones.

During the second quarter, W&T acquired an additional 2,160 net acres of
undeveloped acreage directly offsetting and surrounded by our existing Yellow
Rose field infrastructure and production, increasing our net acreage position
by approximately 10%. The acquired acreage offers us an excellent platform
for growth, continued production expansion, and excellent operational and cost
synergies with our existing core field area. We anticipate additional reserve
bookings during 2013 as a result of this new acreage purchase.

Star Project
We are continuing to monitor our four initial wells that were drilled on our
East Texas acreage and have begun planning our fifth horizontal well. We
expect to commence drilling the fifth well during the fourth quarter of 2013.

Recompletions and Workovers
During the second quarter, we had three offshore recompletions and eight
onshore recompletions for a total cost of $3.3 million. The total impact was
a net initial production gain of 775 Boe per day. Workovers for the quarter
totaled $17.2 million and resulted in a net initial production increase of
2,195 Boe per day. The total cost of workovers for the quarter was abnormally
high due to the inclusion of the Main Pass 69 E-1 well; a rig-based workover
to replace the subsurface safety valve which will allow for incremental
production later this year.

Outlook
Our guidance for the third quarter and full year 2013 is provided in the table
below and represents our best estimate of the range of likely future results.
Our guidance includes an estimated 2.5 Bcfe of potential tropical storm
downtime in the third quarter. These guidance numbers do not reflect the
impact of either potential acquisitions or divestitures. Our results may be
affected by the factors described below in "Forward-Looking Statements."

                                                   Previous      Revised
                                     Third Quarter
Estimated Production                               Full-Year     Full-Year
                                     2013
                                                   2013          2013
Oil and NGLs (MMBbls)                2.0 – 2.3     8.1 – 9.0     9.0 – 9.5
Natural Gas (Bcf)                    10.1 – 11.5   52.9 – 58.5   47.4 – 49.5
Total (Bcfe)                         22.2 – 25.2   102.0 – 112.0 101.3 – 106.5
Total (MMBoe)                        3.7 – 4.2     17.0 – 18.7   16.9 – 17.7
                                                   Previous      Revised
Operating Expenses                   Third Quarter
                                                   Full-Year     Full-Year
($ in millions)                      2013
                                                   2013          2013
Lease operating expenses             $68 - $77     $221 - $244   $249 – $275
Gathering, transportation, &         $7 - $8       $37 - $41     $26 – $31
production taxes
General & administrative             $21 - $24     $78 - $86     $78 – $86
Income tax rate ^(1)                 36%           36%           36%

(1) For income statement purposes only and not a reflection of estimated tax
payments or refunds in 2013.

Conference Call Information: We will hold a conference call to discuss these
financial and operational results on Thursday, August 8, at 10:00 a.m. Eastern
Time. To participate, dial (480) 629-9835 a few minutes before the call
begins. The call will also be broadcast live over the Internet from our
website at www.wtoffshore.com. A replay will be available until August 15 and
may be accessed by calling (303) 590-3030 and using the pass code 4628422#.

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 71 offshore fields in federal and state waters (65 producing and
six fields capable of producing). W&T currently has under lease over 1.4
million gross acres including over 710,000 gross acres on the Gulf of Mexico
Shelf, over 480,000 gross acres in the deepwater and over 220,000 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, 2012 and
on Form 10-Q for the quarter ended March 31, 2013 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 in filings with the SEC. These are our 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 unless the well was included in previously
disclosed proved undeveloped reserve estimates. 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
our interests could differ substantially from our estimates and targets. We
make no commitment to drill all of the drilling locations which have been
attributed these quantities and our drilling plans are subject to revision.
Factors affecting ultimate recovery and reserve estimates and targets include
actual drilling results, including geological and mechanical factors affecting
recovery rates, which will vary from well to well; and 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.. Estimates of targeted
reserves, potential reserves and average well EUR may change significantly as
development of our oil and gas assets provide additional data.

Our production forecasts, estimated and targeted initial production rates and
expectations for future periods are similarly 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. Actual
production will vary from well to well.

W&T OFFSHORE, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Income (Loss)
(Unaudited)
                               Three Months Ended       Six Months Ended
                               June 30,                 June 30,
                               2013         2012        2013        2012
                               (In thousands, except per share data)
Revenues                       $ 235,383    $ 215,513   $ 494,605   $ 451,399
Operating costs and expenses:
Lease operating expenses         68,248       60,276      127,590     116,938
Gathering, transportation        6,388        5,445       12,621      11,151
costs and production taxes
Depreciation, depletion,         99,896       85,941      208,767     174,432
amortization and accretion
General and administrative       19,868       14,623      40,955      44,102
expenses
Derivative gain                  (12,840)     (49,872)    (9,473)     (10,238)
Total costs and expenses         181,560      116,413     380,460     336,385
Operating income                 53,823       99,100      114,145     115,014
Interest expense:
Incurred                         21,536       14,706      42,770      28,612
Capitalized                      (2,532)      (3,326)     (4,964)     (6,517)
 Income before income     34,819       87,720      76,339      92,919
tax expense
Income tax expense              12,423       34,153      27,325      36,134
 Net income             $ 22,396     $ 53,567    $ 49,014    $ 56,785
Basic and diluted earnings     $ 0.29       $ 0.70      $ 0.64      $ 0.75
per common share
Weighted average common          75,223       74,318      75,215      74,309
shares outstanding
Consolidated Cash Flow
Information
Net cash provided by           $ 127,528    $ 113,168   $ 297,362   $ 241,325
operating activities
Capital expenditures             162,587      102,658     299,213     187,284



W&T OFFSHORE, INC. AND SUBSIDIARIES
Condensed Operating Data
(Unaudited)
                                      Three Months Ended   Six Months Ended
                                      June 30,             June 30,
                                      2013       2012      2013       2012
Net sales volumes:
Oil (MBbls)                            1,657      1,451     3,501      2,991
NGL (MBbls)                             491        586       1,026      1,130
Oil and NGLs (MBbls)                    2,148      2,037     4,527      4,120
Natural gas (MMcf)                      11,842     14,320    24,562     28,696
Total oil and natural gas (MBoe)^(1)    4,122      4,423     8,621      8,903
Total oil and natural gas               24,733     26,541    51,726     53,418
(MMcfe)^(1)
Average daily equivalent sales          45.3       48.6      47.6       48.9
(MBoe/d)
Average daily equivalent sales          271.8      291.7     285.8      293.5
(MMcfe/d)
Average realized sales prices
(Unhedged):
Oil ($/Bbl)                           $ 101.78   $ 106.04  $ 104.61   $ 108.28
NGLs ($/Bbl)                            32.17      44.27     33.26      46.31
Oil and NGLs ($/Bbl)                    85.87      88.27     88.43      91.29
Natural gas ($/Mcf)                     4.22       2.49      3.78       2.58
Barrel of oil equivalent ($/Boe)        56.88      48.71     57.22      50.57
Natural gas equivalent ($/Mcfe)         9.48       8.12      9.54       8.43
Average realized sales prices
(Hedged):^(2)
Oil ($/Bbl)                           $ 102.96   $ 105.84  $ 103.95   $ 106.24
NGLs ($/Bbl)                            32.17      44.27     33.26      46.31
Oil and NGLs ($/Bbl)                    86.78      88.13     87.92      89.81
Natural gas ($/Mcf)                     4.22       2.49      3.78       2.58
Barrel of oil equivalent ($/Boe)        57.36      48.64     56.95      49.89
Natural gas equivalent ($/Mcfe)         9.56       8.11      9.49       8.31
Average per Boe ($/Boe):
Lease operating expenses             $ 16.56    $ 13.63   $ 14.80    $ 13.13
Gathering and transportation costs      1.55       1.23      1.46       1.25
and production taxes
Depreciation, depletion,                24.23      19.43     24.22      19.59
amortization and accretion
General and administrative expenses    4.82       3.31      4.75       4.95
Net cash provided by operating          30.94      25.58     34.49      27.11
activities
Adjusted EBITDA                         34.65      30.49     36.09      31.61
Average per Mcfe ($/Mcfe):
Lease operating expenses              $ 2.76     $ 2.27    $ 2.47     $ 2.19
Gathering and transportation costs      0.26       0.21      0.24       0.21
and production taxes
Depreciation, depletion,                4.04       3.24      4.04       3.27
amortization and accretion
General and administrative expenses    0.80       0.55      0.79       0.83
Net cash provided by operating          5.16       4.26      5.75       4.52
activities
Adjusted EBITDA                         5.78       5.08      6.02       5.27

    MMcfe and MBoe 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
(1) rounding). The conversion ratio does not assume price equivalency and the
    price on an equivalent basis for oil, NGLs and natural gas may differ
    significantly.
    Data for all periods presented includes the effects of realized gains and
(2) losses on commodity derivative contracts, none of which qualified for
    hedge accounting.



W&T OFFSHORE, INC. AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
(Unaudited)
                                                    June 30,      December 31,
                                                    2013          2012
                                                    (In thousands, except
                                                    share data)
Assets
Current assets:
Cash and cash equivalents                           $ 9,276       $  12,245
Receivables:
 Oil and natural gas sales                          80,670         97,733
 Joint interest and other                           22,921         56,439
 Income taxes                                       39,556         47,884
 Total receivables                               143,147        202,056
Deferred income taxes                                 -              267
Prepaid expenses and other assets                     37,214         25,555
 Total current assets                          189,637        240,123
Property and equipment – at cost:
 Oil and natural gas properties and
equipment (full cost method, of which $127,918        7,009,835      6,694,510
atJune 30, 2013 and $123,503 at December 31, 2012
were excluded fromamortization)
 Furniture, fixtures and other                 20,848         21,786
 Total property and equipment             7,030,683      6,716,296
 Less accumulated depreciation, depletion      4,851,973      4,655,841
and amortization
Net property and equipment               2,178,710      2,060,455
Restricted deposits for asset retirement              33,469         28,466
obligations
Other assets                                          18,198         19,943
 Total assets                               $ 2,420,014   $  2,348,987
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable                                   $ 123,070     $  123,885
Undistributed oil and natural gas proceeds            42,068         37,073
Asset retirement obligations                         74,687         92,630
Accrued liabilities                                  13,984         21,021
Deferred income taxes - current portion               5,760          -
 Total current liabilities                     259,569        274,609
Long-term debt                                        1,099,537      1,087,611
Asset retirement obligations, less current portion    309,918        291,423
Deferred income taxes                                162,948        145,249
Other liabilities                                     5,864          8,908
Commitments and contingencies                         -              -
Shareholders' equity:
Common stock, $0.00001 par value; 118,330,000
shares authorized; 78,146,253 issued and
75,277,080 outstanding at June 30, 2013;             1              1
78,118,803 issued and75,249,630 outstanding at
December 31, 2012
Additional paid-in capital                           401,097        396,186
Retained earnings                                    205,247        169,167
Treasury stock, at cost                               (24,167)       (24,167)
 Total shareholders' equity                   582,178        541,187
 Total liabilities and shareholders' equity  $ 2,420,014   $  2,348,987



W&T OFFSHORE, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Cash Flows
(Unaudited)
                                                    Six Months Ended
                                                    June 30,
                                                    2013          2012
                                                    (In thousands)
Operating activities:
Net income                                         $ 49,014      $ 56,785
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion, amortization and             208,767       174,432
accretion
Amortization of debt issuance costs and premium      910           1,287
Share-based compensation                              4,950         5,818
Derivative gain                                       (9,473)       (10,238)
Cash payments on derivative settlements              (2,310)       (6,084)
Deferred income taxes                                 23,726        48,120
Asset retirement obligation settlements               (32,886)      (29,228)
Changes in operating assets and liabilities           54,664        433
 Net cash provided by operating activities     297,362       241,325
Investing activities:
Investment in oil and natural gas properties and      (299,213)     (187,284)
equipment
Proceeds from sales of oil and natural gas            -             30,453
properties and equipment
Changes in restricted cash                           -             (30,763)
Purchases of furniture, fixtures and other            (981)         (668)
Net cash used in investing activities                 (300,194)     (188,262)
Financing activities:
Borrowings of long-term debt                         252,000       197,000
Repayments of long-term debt                         (239,000)     (234,000)
Dividends to shareholders                            (12,795)      (11,898)
Other                                                 (342)         (124)
Net cash used in financing activities               (137)         (49,022)
Increase (decrease) in cash and cash equivalents    (2,969)       4,041
Cash and cash equivalents, beginning of period        12,245        4,512
Cash and cash equivalents, end of period           $ 9,276       $ 8,553



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", "Adjusted
EBITDA", and "Adjusted EBITDA Margin". 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, litigation accruals, 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.

Adjusted Net Income
                            Three Months Ended        Six Months Ended
                            June 30,                  June 30,
                            2013         2012         2013         2012
                            (In thousands, except per share amounts)
                            (Unaudited)
Net income                  $ 22,396     $ 53,567     $ 49,014     $ 56,785
Unrealized commodity          (10,879)     (50,157)     (11,783)     (16,322)
derivative gain
Litigation accruals           -            -            -            8,300
Income tax adjustment for
above items at statutory      3,808        17,555       4,124        2,808
rate
Net income excluding        $ 15,325     $ 20,965     $ 41,355     $ 51,571
special items
Basic and diluted earnings
per common share,           $ 0.20       $ 0.28       $ 0.54       $ 0.68
excluding special items

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, and
litigation accruals. Adjusted EBITDA Margin represents the ratio of Adjusted
EBITDA to total revenues. We believe the presentation of EBITDA, Adjusted
EBITDA, and Adjusted EBITDA Margin 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, Adjusted EBITDA, and
Adjusted EBITDA Margin 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,
Adjusted EBITDA, and Adjusted EBITDA Margin, as we calculate them, may not be
comparable to EBITDA, Adjusted EBITDA, and Adjusted EBITDA Margin measures
reported by other companies. In addition, EBITDA, Adjusted EBITDA, and
Adjusted EBITDA Margin 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.

Adjusted EBITDA
                            Three Months Ended        Six Months Ended
                            June 30,                  June 30,
                            2013         2012         2013         2012
                            (In thousands)
                            (Unaudited)
Net income                  $ 22,396     $ 53,567     $ 49,014     $ 56,785
Income tax expense          12,423       34,153       27,325       36,134
Net interest expense        19,013       11,380       37,815       22,094
Depreciation, depletion,      99,896       85,941       208,767      174,432
amortization and accretion
EBITDA                        153,728      185,041      322,921      289,445
Adjustments:
Unrealized commodity          (10,879)     (50,157)     (11,783)     (16,322)
derivative gain
Litigation accruals           -            -            -            8,300
Adjusted EBITDA             $ 142,849    $ 134,884    $ 311,138    $ 281,423
Adjusted EBITDA Margin        61%          63%          63%          62%



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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