W&T Offshore Reports Third Quarter 2013 Financial and Operational Results And Callon Closing

W&T Offshore Reports Third Quarter 2013 Financial and Operational Results And
                                Callon Closing

PR Newswire

HOUSTON, Nov. 6, 2013

HOUSTON, Nov. 6, 2013 /PRNewswire/ --W&T Offshore, Inc. (NYSE: WTI) today
announced financial and operational results for the third quarter of 2013.
Some of the highlights include: 

  oOn October 17, we announced plans to acquire substantially all of Callon
    Petroleum's exploration and production properties in the Gulf of Mexico,
    including its 15% working interest in the Medusa field (deepwater
    Mississippi Canyon blocks 538 and 582) for $100 million, subject to
    post-effective date adjustments with an effective date of July 1, 2013.
    On November 5, we closed on those properties that were not subject to
    third party preferential rights, which represented a substantial portion
    of the reserve value of the Callon transaction. A final closing is
    anticipated by the end of November 2013 for those remaining properties,
    subject to preferential rights that have not been exercised.
  oProduction volumes averaged 45.7 MBoe per day, or 274.4 MMcfe per day
    during the third quarter of 2013, up 13% over the third quarter of 2012.
    Approximately 66% of our increase in revenues was attributable to higher
    production volumes.
  oOil production for the third quarter increased 25.8% over the third
    quarter of last year. Production volumes for the third quarter of 2013
    were split 41.0% oil, 11.8% NGLs and 47.2% natural gas.
  oAdjusted EBITDA was $147.2 million, up $37.5 million or 34% over the third
    quarter of last year, and Adjusted EBITDA Margin was 60%.
  oDrilling operations are currently underway at the Noble operated
    Mississippi Canyon 782 #1 ("Dantzler") deepwater exploration well where
    W&T holds a 20% working interest.
  oIncreased the capital budget for 2013 to $550 million to accommodate the
    addition of the Dantzler project, additional drilling at our Yellow Rose
    field, completion costs resulting from our successful exploration
    drilling, and new seismic and leasehold costs.
  oRevenues were $244.6 million, net income was $14.2 million and earnings of
    $0.19 per share. Net income for the third quarter of 2013, adjusted to
    exclude special items, was $15.5 million or $0.20 per share.
  oAverage realized sales price was $106.70 per barrel for oil, $33.39 per
    barrel for NGLs and $3.66 per Mcf for natural gas.
  oNet cash provided by operating activities for the first nine months of
    2013 was $475.8 million, up from $351.5 million for the comparable 2012
    period.
  oCompleted three offshore wells during the quarter and are currently
    drilling two additional offshore wells and completing one well.
  oCompleted ten onshore wells in the Permian Basin of West Texas (one
    horizontal and eight vertical development wells, and one vertical
    exploration well) during the quarter. After quarter close, we had one
    vertical well completed and six additional vertical wells awaiting
    completion. We are currently drilling one horizontal exploration well in
    our Yellow Rose field in West Texas and one horizontal exploration well in
    East Texas at our Star Prospect.
  oA gas discovery at the deepwater prospect "Troubadour" in Mississippi
    Canyon 699.
  oPaid a dividend of $0.09 per share during the quarter.

Tracy W. Krohn, W&T Offshore's Chairman and Chief Executive Officer, stated,
"Since the third quarter of last year, we increased our oil production by over
25% and increased our NGL production by almost 10%, with revenue from liquids
production now making up 82% of total revenue. We have achieved this growth
both onshore and offshore, and through the drill bit as well as through
acquisitions. Significant contributors to this liquids expansion are our
Mahogany field offshore, the Yellow Rose field in the Permian Basin and
properties we acquired from Newfield Exploration in October 2012. Our
acquisition of oil dominated properties from Callon Petroleum will contribute
to further growth in 2013, in addition to increasing our exposure to the
deepwater. We now have almost 500,000 gross acres in the deepwater which we
believe offers substantial opportunity for further expansion of our oil
production and reserves."

Revenues, Production, and Price: Revenues for the third quarter were $244.6
million compared to $185.9 million in the third quarter of 2012. Overall,
revenues increased due to higher production and better average commodity
prices with the biggest contributors being higher oil production and higher
oil prices. During the third quarter of 2013, we sold 1.7 million barrels of
oil, 0.5 million barrels of natural gas liquids (NGLs) and 11.9 billion cubic
feet (Bcf) of natural gas as compared to 1.4 million barrels of oil, 0.5
million barrels of NGLs and 11.4 Bcf of natural gas for the same period of
2012. In total, we sold 4.2 million barrels of oil equivalent (Boe) at an
average realized sales price of $58.04 per Boe compared to 3.7 million Boe
sold at an average realized sales price of $49.86 per Boe in the third quarter
of 2012. Oil revenues were higher due to a 25.8% increase in sales volumes
and a 6.0% percent increase in prices. NGL revenue increased due to a 20.7%
increase in prices and a 9.5% increase in sales volumes. Natural gas revenues
were higher primarily due to a 19.2% increase in prices and a 4.6% increase in
sales volumes. 

Production for the third quarter of 2013 benefitted from the positive impact
of our Ship Shoal 349 Mahogany production, increased production from our
onshore Yellow Rose field and from the Newfield properties acquired in 2012.
Production was negatively impacted by natural production declines and
production deferrals affecting various fields again in the third quarter of
2013. The production deferrals were attributable to third-party pipeline
outages, platform maintenance, and various operational issues. We estimate
that total production deferrals for the third quarter of 2013 were
approximately 4.7 Bcfe. Production was also deferred in the 2012 period by
tropical storm activity as well as third party pipeline outages.

Net Income & EPS: Third quarter of 2013 net income was $14.2 million, or
$0.19 per common share, compared to net loss of $1.5 million, or ($0.02) per
common share, for the same period in 2012. Net income for the third quarter
of 2013, adjusted to exclude special items, was $15.5 million, or $0.20 per
common share. This compares to net income for the third quarter of 2012,
excluding special items, of $14.4 million, or $0.19 per common share. 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 release.  Adjusted EBITDA for the
third quarter of 2013 was $147.2 million, up from $109.7 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 nine months
of 2013 was $475.8 million, compared to $351.5 million for the same period of
the prior year. During the nine months ended September 30, 2013, we made no
income tax payments and received $59.1 million of refunds. The refunds were
primarily attributable to tax loss carrybacks to 2010 and 2011, and refunds of
2012 estimated federal tax payments. 

As of September 30, 2013, we have spent $45.3 million to date and expect to
incur an additional $2.1 million for removal of wreckage associated with
platforms damaged by Hurricane Ike.

Lease Operating Expenses (LOE): Lease operating expenses, which includes base
lease operating expenses, insurance premiums, workovers and maintenance on our
facilities, were $67.3 million in the third quarter of 2013 compared to the
$53.4 million in the third quarter of 2012. On a component basis, base LOE
increased $8.9 million, workover expense increased $3.8 million and facilities
maintenance increased $2.7 million, partially offset by a $1.5 million
decrease in insurance premiums. Base LOE increased primarily as a result of
the addition of the properties acquired from Newfield during the fourth
quarter of 2012, expanded onshore operations at our Yellow Rose field, and an
ad valorem tax refund and other reductions that occurred in the 2012 period
that did not reoccur in the 2013 period, partially offset by an increase in
processing fees charged to third parties. Workover costs increased with our
expanded onshore activities and operations performed on the A-12 well at
Mahogany. The increase in facilities maintenance was primarily attributable
to a planned maintenance turnaround of our Yellowhammer onshore gas plant
during the quarter. 

Depreciation, Depletion, Amortization, and Accretion (DD&A): DD&A, including
accretion for Asset Retirement Obligation (ARO), increased to $4.13 per Mcfe
for the third quarter of 2013 from $3.47 per Mcfe in the prior year period.
On a nominal basis, DD&A increased to $104.1 million for the third quarter of
2013 from $77.5 million in the prior-year period. DD&A rose on a nominal
basis primarily due to increased production during the third quarter of 2013
when compared to the same period in 2012. The rise in the rate per Mcfe
continues to be related 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 significant 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 also contributed to the increase in our DD&A rate. 

General and Administrative Expenses (G&A): G&A increased to $20.0 million for
the third quarter of 2013 from $18.7 million for the prior-year period
primarily due to increases in contract labor, professional fees and surety
bond fees, partially offset by increased overhead billings to joint interest
partners and lower compensation-related expenses.

Derivatives: For the third quarter of 2013 and 2012, our derivative net
losses were $15.7 million and $24.7 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 third quarter of 2013, the net
derivative loss was composed of a $4.6 million realized and an $11.1 million
unrealized loss. For the third quarter of 2012, the net derivative loss
consisted of a realized loss of $0.9 million and an unrealized loss of $23.8
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 increased to $21.4 million for the third
quarter of 2013 from $14.8 million for the prior-year period. The aggregate
principal amount of our 8.50% Senior Notes outstanding was $900.0 million in
the third 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
third quarter of 2013 and 2012, $2.6 million and $3.4 million, respectively,
of interest was capitalized to unevaluated oil and natural gas properties.
The decrease is primarily attributable to reclassifying certain unevaluated
properties to the full cost pool during the fourth quarter of 2012.

Other Income: Included in Other Income is  $9.2 million that represents a
payment to W&T for an option exercised by a counterparty.

Income Taxes: Income tax expense was $8.0 million for the third quarter of
2013, compared to a $2.2 million income tax benefit for the same period of
2012, primarily attributable to changes in pre-tax income. Our effective tax
rate for the three months ended September 30, 2013 was 36.1% and differed from
the federal statutory rate of 35.0% primarily as a result of state income
taxes.

Capital Expenditures: Our capital expenditures for the first nine months of
2013 were $423.1 million. Capital expenditures were composed of $149.4
million for exploration, $246.1 million for development, and $27.6 million for
leasehold and other costs.  Offshore activities accounted for 69% of the
capital expenditures with 31% allocated to onshore activities.

Operations Review and Update

OFFSHORE

Offshore Wells Completed 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 ST2                     (exploration          Currently producing
 (Mahogany)      100  EXPL Shelf     target). Secondary    approximately 3,200
                                     target in the P sand  Boe per day net.
                                     (development) at
                                     ~14,200' TVD
                                                           Well completed and
                                                           currently
                                                           producing.
                                     Gas and liquids in    Additional pay
 MP 108 B-1 ST   100  EXPL Shelf     Tex W 6 sand at       discovered in the
                                     ~14,880' TVD          Tex W-3 sand will
                                                           serve as future
                                                           recomplete
                                                           opportunity.
                                                           Well completed
                                                           during the third
 HI 21 A-1 BP1                       Gas and liquids at    quarter and final
 (High Island 22 100  DEV  Shelf     ~13,700' in the       topside work was
 field)                              LH-20 sand            completed in
                                                           October. Currently
                                                           producing.
Current Offshore Drilling and Completion Activity in the Fourth Quarter 2013
 Block/Well      WI%  Type Location  Target                Comments
                                     Exploration well
 MC 782 #1       20   EXPL Deepwater with reservoir in     Active drilling
 (Dantzler)                          Lower Miocene         operations.
                                     against salt
                                                           Well logged ~220'
                                     Target in "A" sand    of net pay. Active
 MC 243 A-5      100  EXPL Deepwater (producing            completion
 (Matterhorn)                        reservoir) at         operations. First
                                     ~6,800' TVD           production expected
                                                           during Q4 2013.
                                     Exploration well in   Gas discovery in
 MC 699          20   EXPL Deepwater the block adjacent    7,273' of water.
 (Troubadour)                        to MC 698 "Big Bend"  Well T&A'd for
                                     discovery             future development.
                                     Multiple exploratory
 SS 349 A-15                         oil targets (N, O,    Drilling operations
 (Mahogany)      100  EXPL Shelf     P, Q, Q5 sands) at    to resume in
                                     13,000' to 15,500'    November.
                                     TVD
                                     Targeting new oil
 EC 321 A-2 ST   100  EXPL Shelf     reserves in the       Well operations
                                     Lentic 1 sand at      began in October.
                                     ~8,500 ' TVD



OFFSHORE EXPLORATION AND DEVELOPMENT

Deepwater Gulf of Mexico

During the third quarter, we had a natural gas discovery at the deepwater
exploration prospect, "Troubadour," in Mississippi Canyon ("MC") block 699,
where we hold a 20% working interest. The operator, Noble Energy, has
sanctioned the MC 698 "Big Bend" discovery as a single well sub-sea tie back.
Long lead time equipment orders have commenced and first production is
projected for 2015.

W&T has partnered with Noble Energy in an additional deepwater exploration
well during 2013, the Mississippi Canyon 782 #1 "Dantzler" prospect, with a
20% working interest. Noble estimates that the Dantzler prospect could have a
targeted resource potential of between 50 and 220 million barrels of oil
equivalent. Drilling operations are underway and the well is scheduled to
reach total depth during the fourth quarter, with results expected prior to
year end.

Ship Shoal 349 "Mahogany" Field

As previously reported, we brought the SS 349 "Mahogany" A-14 exploration well
online during July with production from the newly discovered T-sand. The well
has continued to show a strong drive mechanism and has produced an estimated
330,000 Boe gross and 275,000 Boe net (75% crude oil) in its first 90 days.
The company is making plans to drill another development well to recover the
more than 200 feet of net pay uphole from the existing "T" sand completion in
the M, N, O, and P sands.

After completion of the A-14 well, we rig conducted a successful recompletion
of the A-4 well to a new "P" sand which was brought online during early
September at a rate of approximately 1,000 Boe per day gross.

Following the A-4 recompletion, we spud the A-15 deep shelf, sub-salt
exploratory well at Mahogany, which targets five separate stacked sands,
including the N-sand and O-sand which both saw significant pay in the A-14
well logs. After reaching the first casing point, drilling operations were
temporarily suspended for a remedial workover on the A-12 producer. This
operation is expected to conclude soon at which time the A-12 will be placed
back online and drilling operations will resume on the A-15 well. We project
the A-15 well will reach total depth during the first quarter of 2014. Our
estimated target reserve potential for this well is between 1.8 million and
6.2 million barrels of oil equivalent and the target initial production rate
is approximately 1,400 Boe per day net to W&T after royalties. The value
associated with the Ship Shoal 349 field continues to grow with each new
generation of seismic data and each new exploration discovery.

Main Pass 108 Field

The B-1 side-track well at our Main Pass 108 field was brought online during
August at an initial production rate of approximately 5,700 Mcfe per day gross
and 100 barrels of oil gross. Current production is from the Tex W-6 sand,
which was the original target sand for the well. The additional pay found in
the Tex W-3 sand will serve as a future recompletion opportunity for this
field.

Mississippi Canyon 243 "Matterhorn" Field

At our Matterhorn field, we have begun completion operations on the A-5
side-track well, which logged roughly 220 feet of net pay earlier this year.
We expect the completion operations to conclude and first production from the
A-5 near the end of the fourth quarter of 2013. Prior to the mobilization of
the completion unit, the platform underwent various optimization activities
and we performed a recomplete on the A-9 well. Together, these activities
enhanced production from the field which at the end of October was
approximately 5,300 Boe per day, up significantly from last year.

High Island 22 Field

Completion operations and pipeline tie-back for the High Island 21 A-1 well
took place during October, and the well was brought on production. The well
is producing from the LH-20 series sands. The well discovered six separate
pay zones, culminating in a total of approximately 225 net feet of pay. The
upper zones will serve as future recompletion opportunities and could result
in reserve additions this year.

East Cameron 321 Field

At our East Cameron 321 field, the rig is now on location and has begun
operations on our exploratory side-track well. The target initial production
rate is approximately 850 Boe per day net to W&T after royalties and is
expected in the late fourth quarter. Our target reserve potential for this
project is 1.1 MMBoe.

West Cameron 73 #2

The 2012 discovery at our non-operated West Cameron 73 field is still expected
to have final pipeline hook-up completed and first production during the
fourth quarter of 2013.

ONSHORE

Onshore Wells Completed in Third Quarter 2013
 Project & Area WI% Type  # of   Target           Comments
                          Wells
Permian Basin
 Yellow Rose    100 DEV   1      Horizontal       1 well on flowback
 Horizontal                      Wolfcamp "A"
 Yellow Rose                     4,500' vertical  5 wells on production, 3
 80 Acre        100 DEV   8      section in the   wells on flowback
 Verticals                       Wolfberry
 Yellow Rose                     4,500' vertical
 40 Acre        100 EXP   1      section in the   1 well on production
 Verticals                       Wolfberry
Current Onshore Well Activity in the Fourth Quarter 2013
 Project & Area WI% Type  # of   Target           Comments
                          Wells
Permian Basin
 Yellow Rose        EXP &        4,500' vertical  1 well completed and on
 80 Acre        100 DEV   5      section in the   flowback, 4 wells awaiting
 Verticals                       Wolfberry        completion
 Yellow Rose                     4,500' vertical
 40 Acre        100 DEV   1      section in the   1 well awaiting completion
 Verticals                       Wolfberry
 Yellow Rose    100 EXP   1      Horizontal       1 well drilling
 Horizontal                      Wolfcamp "B"
Star Prospect
 East Texas     97  EXP   1      Oil window of    1 well drilling
 Horizontal                      James Lime

ONSHORE EXPLORATION AND DEVELOPMENT

Yellow Rose Project

During the third quarter, we continued to operate two rigs in the Permian
Basin at our Yellow Rose field, completing nine new vertical wells (one of
which was an exploration well) and one horizontal development well. The third
quarter average daily production was 3,944 Boe per day net to W&T after
royalties. This is up 63.5% over the average daily production rate in the
third quarter of the previous year and is a 6.8% increase over the second
quarter average daily production rate of 3,694 net Boe per day net to W&T
after royalties. We continue to see strong 30 day average initial production
rates from our recent verticals and have continued with our 40 acre spacing
tests. As part of our expanded capital budget program, we expect to drill
approximately seven additional vertical wells at Yellow Rose during the fourth
quarter of 2013.

Recently we spud the first horizontal Wolfcamp B well on our acreage in Martin
County. Nearby, offset operators have shown recent success with solid results
from lateral lengths just over 4,000 feet as well as lateral lengths of over
7,000 feet. Our initial Wolfcamp B horizontal well has a planned lateral
length in excess of 6,000 feet. We expect to complete the well and have
results by year end.

The northward expansion and growth in activity surrounding our acreage is
reflective of not only the potential, but significant value tied to our
current acreage position. Although our current horizontal well is targeting
the Wolfcamp B, we will continue to evaluate other potential benches which we
may test in the coming months. We continue to collect and analyze detailed
data on those formations including log data and core data.

Star Project

At our Star Project in East Texas, we recently spud our fifth horizontal well
targeting oil in the James Lime at about 8,500 feet true vertical depth with a
planned lateral length of just over 6,000 feet. We expect to complete the
well during the fourth quarter. We continue to monitor production from our
initial four wells and are closely evaluating the activity of nearby operators
in the area.

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 results may be affected by the factors described below in
"Forward-Looking Statements."

                                                   Previous      Revised
                                    Fourth Quarter
Estimated Production                               Full-Year     Full-Year
                                    2013
                                                   2013          2013
Oil and NGLs (MMBbls)               2.2 – 2.5      9.0 – 9.5     9.0 – 9.3
Natural Gas (Bcf)                12.7 – 14.4    47.4 – 49.5   49.2 – 50.9
 Total (Bcfe)                  26.2 – 29.5    101.3 – 106.5 103.2 – 106.5
 Total (MMBoe)                  4.4 – 4.9      16.9 – 17.7   17.2 – 17.7
                                                                 
                                                   Previous
Operating Expenses                  Fourth Quarter               Revised
                                                   Full-Year
($ in millions)                     2013                         Full-Year
                                                   2013
                                                                 2013
Lease operating expenses            $65 - $75      $249 – $275   $260 - $270
Gathering, transportation, &        $5 - $9        $26 – $31     $23 - $27
production taxes
 General & administrative          $19 - $25      $78 – $86     $80 - $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, November 7, 2013 at 9:30 a.m.
Eastern Time. To participate, dial (480) 629-9770 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 November 14,
2013 and may be accessed by calling (303) 590-3030 and using the pass code
4645500#.

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 67 offshore fields in federal and state waters (60 producing and
seven fields capable of producing). W&T currently has under lease
approximately 1.3 million gross acres including approximately 0.6 million
gross acres on the Gulf of Mexico Shelf, approximately 0.5 million acres in
the deepwater and approximately 0.2 million 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 June 30, 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.

CONTACT: Mark Brewer                      Danny Gibbons
          Investor Relations               SVP & CFO
          investorrelations@wtoffshore.com  investorrelations@wtoffshore.com





W&T OFFSHORE, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Income (Loss)
(Unaudited)
                                  Three Months Ended     Nine Months Ended
                                  September 30,          September 30,
                                  2013        2012       2013        2012
                                  (In thousands, except per share data)
Revenues^                        $ 244,555   $ 185,946  $ 739,160   $ 637,345
Operating costs and expenses:
Lease operating expenses          67,346      53,411     194,935     170,349
Gathering, transportation costs     5,418       4,163      18,038      15,314
and production taxes
Depreciation, depletion,            104,143     77,462     312,911     251,894
amortization and accretion
General and administrative          20,024      18,691     60,979      62,793
expenses
Derivative loss                     15,659      24,659     6,186       14,421
 Total costs and expenses        212,590     178,386    593,049     514,771
 Operating income                31,965      7,560      146,111     122,574
Interest expense:
Incurred                            21,373      14,791     64,157      43,409
Capitalized                         (2,573)     (3,383)    (7,537)     (9,899)
Other income                        9,062       202        9,075       210
 Income (loss) before income       22,227      (3,646)    98,566      89,274
tax expense (benefit)
Income tax expense (benefit)       8,033       (2,175)    35,358      33,959
 Net income (loss)              $ 14,194    $ (1,471)  $ 63,208    $ 55,315
Basic and diluted earnings        $ 0.19      $ (0.02)   $ 0.83      $ 0.73
(loss) per common share
Weighted average common shares      75,233      74,327     75,221      74,315
outstanding
Consolidated Cash Flow
Information
Net cash provided by operating    $ 178,471   $ 110,164  $ 475,833   $ 351,489
activities
Capital expenditures                123,879     125,088    423,092     312,372



W&T OFFSHORE, INC. AND SUBSIDIARIES
Condensed Operating Data
(Unaudited)
                                 Three Months Ended
                                 September 30,                   Variance
                                 2013       2012      Variance  Percentage^(2)
Net sales volumes:
Oil (MBbls)                      1,725      1,371     354     25.8%
NGL (MBbls)                       494        451       43      9.5%
Oil and NGLs (MBbls)               2,220      1,822     398     21.8%
Natural gas (MMcf)                11,924     11,401    523     4.6%
Total oil and natural gas          4,207      3,722     485     13.0%
(MBoe)^(1)
Total oil and natural gas          25,241     22,331    2,910   13.0%
(MMcfe)^(1)
Average daily equivalent sales     45.7       40.5      5.2     12.8%
(MBoe/d)
Average daily equivalent sales     274.4      242.7     31.7    13.1%
(MMcfe/d)
Average realized sales prices
(Unhedged):
Oil ($/Bbl)                      $ 106.70   $ 100.68  $ 6.02    6.0%
NGLs ($/Bbl)                       33.39      27.66     5.73    20.7%
Oil and NGLs ($/Bbl)               90.38      82.62     7.76    9.4%
Natural gas ($/Mcf)                3.66       3.07      0.59    19.2%
Barrel of oil equivalent           58.04      49.86     8.18    16.4%
($/Boe)
Natural gas equivalent ($/Mcfe)    9.67       8.31      1.36    16.4%
Average per Boe ($/Boe):
Lease operating expenses        $ 16.01    $ 14.35   $ 1.66    11.6%
Gathering and transportation       1.29       1.12      0.17    15.2%
costs and production taxes
Depreciation, depletion,           24.76      20.81     3.95    19.0%
amortization and accretion
General and administrative         4.76       5.02      (0.26)  -5.2%
expenses
Net cash provided by operating     42.42      29.60     12.82   43.3%
activities
Adjusted EBITDA                    34.99      29.48     5.51    18.7%
Average per Mcfe ($/Mcfe):
Lease operating expenses        $ 2.67     $ 2.39    $ 0.28    11.7%
Gathering and transportation       0.21       0.19      0.02    10.5%
costs and production taxes
Depreciation, depletion,           4.13       3.47      0.66    19.0%
amortization and accretion
General and administrative         0.79       0.84      (0.05)  -6.0%
expenses
Net cash provided by operating     7.07       4.93      2.14    43.4%
activities
Adjusted EBITDA                    5.83       4.91      0.92    18.7%



    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.
(2) Variance percentages are calculated using rounded figures and may result
    in slightly different figures for comparable data.





W&T OFFSHORE, INC. AND SUBSIDIARIES
Condensed Operating Data
(Unaudited)
                                Nine Months Ended
                                September 30,                    Variance
                                2013       2012      Variance   Percentage^(2)
Net sales volumes:
Oil (MBbls)                     5,226      4,361     865      19.8%
NGL (MBbls)                      1,520      1,581     (61)     -3.9%
Oil and NGLs (MBbls)              6,747      5,942     805      13.5%
Natural gas (MMcf)               36,486     40,097    (3,611)  -9.0%
Total oil and natural gas         12,828     12,625    203      1.6%
(MBoe)^(1)
Total oil and natural gas         76,967     75,749    1,218    1.6%
(MMcfe)^(1)
Average daily equivalent sales    47.0       46.1      0.9      2.0%
(MBoe/d)
Average daily equivalent sales    281.9      276.5     5.4      2.0%
(MMcfe/d)
Average realized sales prices
(Unhedged):
Oil ($/Bbl)                     $ 105.30   $ 105.89  $ (0.59)   -0.6%
NGLs ($/Bbl)                      33.30      40.99     (7.69)   -18.8%
Oil and NGLs ($/Bbl)              89.07      88.63     0.44     0.5%
Natural gas ($/Mcf)               3.74       2.72      1.02     37.5%
Barrel of oil equivalent          57.49      50.36     7.13     14.2%
($/Boe)
Natural gas equivalent            9.58       8.39      1.19     14.2%
($/Mcfe)
Average per Boe ($/Boe):
Lease operating expenses       $ 15.20    $ 13.49   $ 1.71     12.7%
Gathering and transportation      1.41       1.21      0.20     16.5%
costs and production taxes
Depreciation, depletion,          24.39      19.95     4.44     22.3%
amortization and accretion
General and administrative        4.75       4.97      (0.22)   -4.4%
expenses
Net cash provided by operating    37.09      27.84     9.25     33.2%
activities
Adjusted EBITDA                   35.73      30.98     4.75     15.3%
Average per Mcfe ($/Mcfe):
Lease operating expenses       $ 2.53     $ 2.25    $ 0.28     12.4%
Gathering and transportation      0.23       0.20      0.03     15.0%
costs and production taxes
Depreciation, depletion,          4.07       3.33      0.74     22.2%
amortization and accretion
General and administrative        0.79       0.83      (0.04)   -4.8%
expenses
Net cash provided by operating    6.18       4.64      1.54     33.2%
activities
Adjusted EBITDA                   5.96       5.16      0.80     15.5%



    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.
(2) Variance percentages are calculated using rounded figures and may result
    in slightly different figures for comparable data.



W&T OFFSHORE, INC. AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
(Unaudited)
                                                  September 30,   December 31,
                                                  2013            2012
                                                  (In thousands, except
                                                  share data)
Assets
Current assets:
Cash and cash equivalents                         $  15,227       $  12,245
Receivables:
 Oil and natural gas sales                         85,221          97,733
 Joint interest and other                          31,492          56,439
 Income taxes                                      -               47,884
 Total receivables                              116,713         202,056
Restricted cash and cash equivalents                 16,459          -
Prepaid expenses and other assets                    32,850          25,822
 Total current assets                               181,249         240,123
Property and equipment – at cost:
 Oil and natural gas properties and equipment
(full costmethod, of which $129,584 at
September 30, 2013 and $123,503 at December 31,
2012 were excluded from
amortization)                                        7,120,086       6,694,510
 Furniture, fixtures and other                      21,325          21,786
 Total property and equipment                    7,141,411       6,716,296
 Less accumulated depreciation, depletion and       4,950,768       4,655,841
amortization
 Net property and equipment                      2,190,643       2,060,455
Restricted deposits for asset retirement             34,966          28,466
obligations
Other assets                                         16,842          19,943
 Total assets                                    $  2,423,700    $  2,348,987
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable                                  $  129,988      $  123,885
Undistributed oil and natural gas proceeds           41,278          37,073
Asset retirement obligations                        95,014          92,630
Accrued liabilities                                  51,048          21,021
 Total current liabilities                          317,328         274,609
Long-term debt                                       1,052,984       1,087,611
Asset retirement obligations, less current           267,093         291,423
portion
Deferred income taxes                                177,404         145,249
Other liabilities                                    15,859          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 September
30, 2013; 78,118,803 issued and
75,249,630 outstanding at December 31, 2012          1               1
Additional paid-in capital                           404,604         396,186
Retained earnings                                    212,594         169,167
Treasury stock, at cost                              (24,167)        (24,167)
 Total shareholders' equity                         593,032         541,187
 Total liabilities and shareholders' equity      $  2,423,700    $  2,348,987



W&T OFFSHORE, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Cash Flows
(Unaudited)
                                                    Nine Months Ended
                                                    September 30,
                                                    2013          2012
                                                    (In thousands)
Operating activities:
Net income                                         $ 63,208      $ 55,315
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion, amortization and             312,911       251,894
accretion
Amortization of debt issuance costs and premium      1,366         2,046
Share-based compensation                            8,457         9,137
Derivative loss                                     6,186         14,421
Cash payments on derivative settlements             (6,855)       (6,960)
Deferred income taxes                               31,581        44,465
Asset retirement obligation settlements             (59,188)      (63,150)
Changes in operating assets and liabilities          118,167       44,321
 Net cash provided by operating activities          475,833       351,489
Investing activities:
Investment in oil and natural gas properties and      (423,092)     (312,372)
equipment
Proceeds from sales of assets and other, net         21,011        30,453
Change in restricted cash                            (16,459)      (24,026)
Deposit for acquisition                               -             (22,800)
Purchases of furniture, fixtures and other           (1,327)       (2,125)
Net cash used in investing activities                (419,867)     (330,870)
Financing activities:
Borrowings of long-term debt                         335,000       316,000
Repayments of long-term debt                         (368,000)     (314,000)
Dividends to shareholders                            (19,570)      (17,848)
Debt issuance costs                                   (164)         (2,081)
Other                                                 (250)         (209)
Net cash used in financing activities                (52,984)      (18,138)
Increase in cash and cash equivalents                2,982         2,481
Cash and cash equivalents, beginning of period       12,245        4,512
Cash and cash equivalents, end of period           $ 15,227      $ 6,993



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, a contract option fee, 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.

                                Three Months Ended      Nine Months Ended
                                September 30,           September 30,
                                2013        2012        2013        2012
                                (In thousands, except per share amounts)
                                (Unaudited)
Net income (loss)              $ 14,194    $ (1,471)   $ 63,208    $ 55,315
Unrealized commodity              11,114      23,784      (669)       7,461
derivative (gain) loss
Contract option fee              (9,065)     -           (9,065)     -
Litigation accruals              -           700         -           9,000
Income tax adjustment for         (717)       (8,569)     3,407       (5,761)
above items at statutory rate
Net income excluding special    $ 15,526    $ 14,444    $ 56,881    $ 66,015
items
Basic and diluted earnings per
common share, excluding         $ 0.20      $ 0.19      $ 0.75      $ 0.87
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, a contract
option fee, 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.

                                Three Months Ended      Nine Months Ended
                                September 30,           September 30,
                                2013        2012        2013        2012
                                (In thousands)
                                (Unaudited)
Net income (loss)               $ 14,194    $ (1,471)   $ 63,208    $ 55,315
Income tax expense (benefit)      8,033       (2,175)     35,358      33,959
Net interest expense              18,798      11,406      56,613      33,500
Depreciation, depletion,          104,143     77,462      312,911     251,894
amortization and accretion
EBITDA                            145,168     85,222      468,090     374,668
Adjustments:
Unrealized commodity              11,114      23,784      (669)       7,461
derivative (gain) loss
Contract option fee               (9,065)     -           (9,065)     -
Litigation accruals               -           700         -           9,000
Adjusted EBITDA                 $ 147,217   $ 109,706   $ 458,356   $ 391,129
Adjusted EBITDA Margin            60%         59%         62%         61%

SOURCE W&T Offshore, Inc.

Website: http://www.wtoffshore.com
 
Press spacebar to pause and continue. Press esc to stop.