CLSA Energy Forum
New York
May 11, 2011
Exhibit 99.1

1
1
Current Snapshot
(1) Data as of 12/31/10, except for number of producing fields.
(2) Includes 6,628 gross and 4,644 net acres onshore.
(3) Excludes recently announced Permian acquisition and the pending fourth Shell property.
Key Financials ($ in MMs)
1Q11
2010
2009
Reserve Data
2010
2009
Revenue
$211
$706
$611
Proved Reserves (Bcfe)
485
371
Adjusted EBITDA
$133
$450
$341
Proved Developed %
81
%
76
%
CAPEX
$40
$416
$276
Oil and Liquids %
47
%
55
%
Field Statistics
(1)
Current Production
(3)
# of Producing Fields w/WI
68
Average Daily Production (MMcfe)
273+/-
Approx. Acreage (Gross/Net)
(2)
853,603 / 553,485
Oil and Liquids %
43
%
% Held-by-Production
82
%
Operated Production % (net)
78
%
2011 Guidance
$ MM
~$/Mcfe
~$/Boe
Production (Bcfe)
87.0 -
101.1
Lease Operating Expense
$190 -
$220
$2.18
$13.08
Gathering, Transportation & Taxes
$25 -
$28
$0.29
$1.74
General & Administrative
$69 -
$80
$0.79
$4.74

2
2
Key Investment Considerations
1)
R/P increases from 5.2 to 6.5 years and W&T’s
% of oil / liquids
increases from 47% to 58% with recently announced onshore
acquisition
2)
Adding Permian Basin to the portfolio with recent acquisition
–
Oily, longer-lived proved reserves
–
Provides “predictable growth”
opportunities, and complements our shelf and
deepwater assets with high cash flow and upside potential
3)
Large acreage position in the Gulf of Mexico primarily held by
production –
27 years of operating safely in the GOM
4)
Balanced mix of oil to gas reserves and production with growing oil
production
5)
Strong cash flow & good liquidity
6)
Active drilling program with 36 (27 onshore, 9 offshore) wells
planned on capital program of $310 million

3
3
Company Diversification in Progress
•
Since April 2010, we have diversified our existing portfolio by
acquiring producing assets at attractive prices in the deepwater
GOM and the Permian basin
(1) Pro forma for recently announced Permian basin acquisition.
Permian Basin
(1)
•
Proved Reserves:  164 Bcfe
/                    
27 MMBoe
•
Acreage:  30,900 Net
•
~6% of Production
GOM Deepwater
•
Proved Reserves:
144 Bcfe
/ 
24 MMBoe
•
Acreage: 137,792 Gross /
93,670 Net
•
~31% of Production
(1)
GOM Shelf
•
Proved Reserves: 341 Bcfe
/ 
57 MMBoe
•
Acreage:  709,183 Gross /
455,171 Net
•
~62% of Production
(1)
Gulf Coast

4
4
Company Strategy –
Focus on Growth
•
Complete pending GOM Shelf acquisition with Shell Offshore
•
Effectively incorporate recently announced acquisition of
West Texas property into existing operations
•
Exploit
recently
acquired
Shell
properties
-
Tahoe
and
S.E.
Tahoe properties
•
Continue evaluations of other potential acquisitions.  Divest
“non-core”
properties as appropriate
•
Pursue active and balanced drilling program to increase
reserves and production
•
Expand/acquire acreage positions in onshore prospect areas

Onshore

6
6
Permian Basin Acquisition Provides Base
for Transformation
•
Signed purchase and sale agreement to acquire approximately
21,900 gross acres (21,500 net acres) from private sellers for
approximately $377 million
•
Strong volumes from proved developed production
–
Current gross daily production of about 2,800 BOE
–
Production grew ~47% from 1,900 BOE at Jan. 1, 2011
–
Currently 70 producing wells
•
Proved and probable reserves
–
27 MMBOE of proved reserves 
–
26 MMBOE of additional probable reserves
•
Conservative estimates of reserves
–
Assumed
an
average
EUR
of
~100
MBOE
net
per
well
for
PUDs
and
40
acres
spacing in our analyses
•
High ratio of oil and liquid (91%) to gas production and reserves
–
R/P increases from 5.2 to 6.5 years and W&T’s % of oil / liquids increases
from 47% to 58%.

7
7
Permian Basin Acquisition Provides
Long-term Growth
•
Low risk operations with a multi-year extensive drilling inventory
–
450
to
500
drilling
locations
indentified
for
future
exploration
and
development
–
Currently operating on 40 acre spacing but certain nearby operators are using
20 acre spacing
–
3 drilling and 2 workover rigs working
•
Plan for three drilling rigs working throughout remainder of 2011
–
Primarily targeting the “Wolfberry”
trend, but deeper targets have been tested
and are producing
–
2011
Capital
Expenditures
of
$35
Million
-
$40
million
–
Expect to drill 7 exploratory & 15-20 developmental wells in 2011

8
8
Newly Acquired Assets in West Texas
: Martin, Dawson, Andrews & Gaines Counties

Wolfberry West Texas Completions *
Limestone Pay
Organic Rich Shale Play
Average Cased Depth
of Wellbore
Fractured Stimulation
Stages
Clear-
fork
Dean
Non-organic Shale Non-pay
Sandstone Play
12,500’
13,250’
Devonian
Silurian
* Not drawn to scale.

10
10
Onshore 2011 Drilling Program
South Texas
WI: 50%
2 Wells
East Texas
WI: 25%
1 well
Exploration
Development
West Texas
WI: 25% to 100%
7 -
8 Wells
West Texas
WI: 100%
15 –
20 Wells
•
In addition to the recently announced
Permian acquisition, we have also
acquired 9,400 net exploratory acres in
the Permian basin

Gulf of Mexico

12
Gulf of Mexico Attributes
•
Great history of production and reserves
–
Highly prolific with multiple pay zones
–
Reserves at deeper but virtually untapped zones, significant
upside potential
–
Established infrastructure on shelf
–
Substantial percentage of oil reserves
–
Reserve to production profile is consistent
•
Attractive reservoir characteristics
–
High porosity rock provides quick return on investment
–
Cash flow velocity significantly higher than most other basins
–
Balanced growth opportunities (high impact or low risk)

13
Our Historical Gulf of Mexico Focus
•
Operating successfully in the Gulf of Mexico for 27 yrs
–
10 year exploration drilling success rate of 77%
–
10 year development drilling success rate of 91%
–
Established infrastructure allows for accelerated cash flow
–
Excellent safety track record and culture for operating excellence
•
Large acreage position
–
WTI
holds
interest
in
about
67
fields
-
spread
across
the
GOM
–
Significant  reserve upside potential in deeper zones
–
Extensive seismic, production and log data
–
Quality prospect inventory
•
Costs historically adjust quickly to commodity prices due to
shorter contract terms
•
Historically active M&A and joint venture market that has the
potential to be even more active in 2011

14
14
Gulf of Mexico Proved Reserve with
Geographic Diversification
•
67 fields
•
78% operated
•
548,841 net acres
•
82% held by production
•
Producing 272 MMcfe per day
•
43% oil & liquids / 57% gas

15
Recent Deepwater Acquisitions
15
Shell
Total
Number of Deepwater
Properties Acquired
3
2
Close date
11/3/2010
5/3/2010
Purchase Price ($MM)
(1)
$138
$150
Proved Res. (MMBoe)
(1)
13.9
11.6
Purchase Price per Unit
(1)
$1.66/Mcfe; $9.93/Boe
$2.15/Mcfe; $12.90/Boe
% Liquids
(2)(3)
10%
64%
Block locations
VK 783 & 784, GC 244
MC 243, VK 822 & 823
~ Current net daily prod.
(3)
8.2 Mboe
4.7 Mboe
(1) As of effective date.
(2) Determined using the ratio of six Mcf of natural gas to one barrel of crude oil or NGL.
(3) Average daily production for March 2011.
Sellers

16
16
Investment Highlights of Conventional
Shelf Property
•
Letter of intent to acquire a fourth field from Shell Offshore, Inc.
which is located in water depth of 20 to 30 feet
•
W&T will be operator and have a large ownership position
–
64.3% working interest
•
Strong volumes from proved developed production
–
Net daily production of 21.6 MMcfe
in March
•
Associated gas treatment plant to be acquired

17
17
Main Pass 108 Field  -
Back Online
•
Pipeline was down since June 2010 and affected production
at  MP 98, MP 108, MP 163 and MP 180 fields
•
Production is back online as of March 31, 2011 via a new
pipeline route
–
Netbacks should increase with the new route
•
High-yield condensate field with net production of
46
MMcfe
per
day,
or
38
MMcf
and
1,400
barrels
per
day
–
We expect the rate to increase another eight to 10 MMcfe
per day when the Main Pass 108 E-3 well comes online

18
18
Concentrated Operations in Recently
Acquired GOM Fields and Focus Areas

19
19
Offshore 2011 Drilling Program
Viosca
Knoll
Mississippi Canyon
Atwater Valley
Green Canyon
Garden Banks
East Breaks
Mustang
Island
Matagorda
Island
Brazos
Galveston
High
Island
E.
Cameron
Vermilion
Eugene
Island
Ship
Shoal
South
Timbalier
Ewing
Bank
West
Delta
Grand
Isle
Main
Pass
S. and E.
Main
Pass
W.
Cameron
Exploration
Development
MP 180 A-2
WI: 100%
Shelf
(Drilled and
successful)
SS 349 B
WI: 100%
Shelf
MP 108 #8 & Tex W5
WI: 75%
Shelf
West Cameron 73  #2
WI: 30%
Deep Shelf
Deepwater
Prospect
WI: 20%
MP 108 D-3 ST
WI: 100%
Shelf
(Drilling)
SS 349 E
WI: 100%
Shelf
ST 316 A-2 ST
WI: 40%
Shelf

20
Regulatory Developments --
Deepwater
•
Ten drilling permits approved since such work was halted
after last year’s spill (as of 5/8/11)
•
Well
control
options
–
Operators
to
show
how
they
would
respond to subsea well control issue.
–
Helix Well Containment Group (HWCG)
–
Marine Well Containment Company (MWCC)
–
Total Deepwater Solution (TDWS)
•
W&T has executed a contract with HWCG
•
The first 3 approved deepwater drilling permit were
members of the HWCG

Other Operational and Financial
Information

22
22
Proved Reserves by Year
PDP
43%
PDNP
33%
PUD
24%
PDP
49%
PDNP
32%
PUD
19%
2010
2009
2010 proved reserves increased 31% over 2009
485
Bcfe
371
Bcfe

23
23
Production Profile
51.6
44.7
43.2
42.3
0.0
20.0
40.0
60.0
80.0
100.0
120.0
140.0
2009
2010
2011E
Oil & NGLs
(Bcfe)
Natural Gas (Bcf)
94.8
Full-Year
Guidance
87.0 –
101.1
87.0
1Q
22.7
51.6
44.7
43.2
42.3
0.0
20.0
40.0
60.0
80.0
100.0
120.0
140.0
2009
2010
2011E
Oil & NGLs
(Bcfe)
Natural Gas (Bcf)
94.8
Full-Year
Guidance
87.0 –
101.1
87.0
1Q
22.7

24
24
Drilling Within Cash Flow
Adjusted EBITDA vs. Capital Expenditures
($ in millions)
Capital
expenditures
funded
largely
through
internally
generated
cash
flow
$884
$820
$341
$450
$687+
$416
$276
$775
$359
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
2007
2008
2009
2010
2011E
Adj. EBITDA
CAPEX, Excl. Acquisitions
Acquisition CAPEX
$884
$820
$341
$450
$687+
$416
$276
$775
$359
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
2007
2008
2009
2010
2011E
Adj. EBITDA
CAPEX, Excl. Acquisitions
Acquisition CAPEX

25
25
W&T’s
Strong Liquidity
•
Cash balance at April 26, 2011 ~ $140 million
•
New four-year revolver with $525 million borrowing
base
•
Borrowing base increases to $575 million when the
fourth Shell property closes; the newly acquired
Permian Basin assets have yet to be considered
•
Net cash provided by operating activities $464.8
million for 2010*
* includes $99.8 million tax reimbursement

26
26
Key Investment Considerations
1)
R/P increases from 5.2 to 6.5 years and W&T’s
% of oil / liquids
increases from 47% to 58% with recently announced onshore
acquisition
2)
Adding Permian Basin to the portfolio with recent acquisition
–
Oily, longer-lived proved reserves
–
Provides “predictable growth”
opportunities, and complements our shelf and
deepwater assets with high cash flow and upside potential
3)
Large acreage position in the Gulf of Mexico primarily held by
production –
27 years of operating safely in the GOM
4)
Balanced mix of oil to gas reserves and production with growing oil
production
5)
Strong cash flow & good liquidity
6)
Active drilling program with 36 (27 onshore, 9 offshore) wells
planned on capital program of $310 million

27
Reconciliation of Net Income to EBITDA
We
define
EBITDA
as
net
income
(loss)
plus
income
tax
expense
(benefit),
net
interest
expense
(which
includes
interest
income),
depreciation,
depletion,
amortization
and
accretion
and
impairment
of
oil
and
natural
gas
properties.
Adjusted
EBITDA
excludes
the
loss
on
extinguishment
of
debt,
the
unrealized
gain
or
loss
related
to
our
derivative
contracts
and
other
items
as
described
above.
Although
not
prescribed
under
GAAP,
we
believe
the
presentation
of
EBITDA
and
Adjusted
EBITDA
provide
useful
information
regarding
our
ability
to
service
debt
and
fund
capital
expenditures
and
they
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.
EBITDA
and
Adjusted
EBITDA
should
not
be
considered
in
isolation
from
or
as
a
substitute
for
net
income,
as
an
indication
of
operating
performance
or
cash
flow
from
operating
activities
or
as
a
measure
of
liquidity.
EBITDA
and
Adjusted
EBITDA,
as
we
calculate
them,
may
not
be
comparable
to
EBITDA
and
Adjusted
EBITDA
measures
reported
by
other
companies.
In
addition,
EBITDA
and
Adjusted
EBITDA
do
not
represent
funds
available
for
discretionary
use.
The following table presents a reconciliation of our consolidated net income to
consolidated EBITDA to Adjusted EBITDA:

28
Forward-Looking Statement Disclosure
This
presentation,
contains
“forward-looking
statements”
within
the
meaning
of
the
Private
Securities
Litigation
Reform
Act
of
1995,
Section
27A
of
the
Securities
Act
and
Section
21E
of
the
Exchange
Act.
Forward-looking
statements
give
our
current
expectations
or
forecasts
of
future
events.
They
include
statements
regarding
our
future
operating
and
financial
performance.
Although
we
believe
the
expectations
and
forecasts
reflected
in
these
and
other
forward-looking
statements
are
reasonable,
we
can
give
no
assurance
they
will
prove
to
have
been
correct.
They
can
be
affected
by
inaccurate
assumptions
or
by
known
or
unknown
risks
and
uncertainties.
You
should
understand
that
the
following
important
factors,
could
affect
our
future
results
and
could
cause
those
results
or
other
outcomes
to
differ
materially
from
those
expressed
or
implied
in
the
forward-looking
statements
relating
to:
(1)
amount,
nature
and
timing
of
capital
expenditures;
(2)
drilling
of
wells
and
other
planned
exploitation
activities;
(3)
timing
and
amount
of
future
production
of
oil
and
natural
gas;
(4)
increases
in
production
growth
and
proved
reserves;
(5)
operating
costs
such
as
lease
operating
expenses,
administrative
costs
and
other
expenses;
(6)
our
future
operating
or
financial
results;
(7)
cash
flow
and
anticipated
liquidity;
(8)
our
business
strategy,
including
expansion
into
the
deep
shelf
and
the
deepwater
of
the
Gulf
of
Mexico,
and
the
availability
of
acquisition
opportunities;
(9)
hedging
strategy;
(10)
exploration
and
exploitation
activities
and
property
acquisitions;
(11)
marketing
of
oil
and
natural
gas;
(12)
governmental
and
environmental
regulation
of
the
oil
and
gas
industry;
(13)
environmental
liabilities
relating
to
potential
pollution
arising
from
our
operations;
(14)
our
level
of
indebtedness;
(15)
timing
and
amount
of
future
dividends;
(16)
industry
competition,
conditions,
performance
and
consolidation;
(17)
natural
events
such
as
severe
weather,
hurricanes,
floods,
fire
and
earthquakes;
and
(18)
availability
of
drilling
rigs
and
other
oil
field
equipment
and
services.
We
caution
you
not
to
place
undue
reliance
on
these
forward-looking
statements,
which
speak
only
as
of
the
date
of
this
presentation
or
as
of
the
date
of
the
report
or
document
in
which
they
are
contained,
and
we
undertake
no
obligation
to
update
such
information.
The
filings
with
the
SEC
are
hereby
incorporated
herein
by
reference
and
qualifies
the
presentation
in
its
entirety.
Cautionary
Note
to
U.S.
Investors
The
United
States
Securities
and
Exchange
Commission
permits
oil
and
gas
companies,
in
their
filings
with
the
SEC,
to
disclose
only
proved
reserves
that
a
company
has
demonstrated
by
actual
production
or
conclusive
formation
tests
to
be
economically
and
legally
producible
under
existing
economic
and
operating
conditions.
U.S.
Investors
are
urged
to
consider
closely
the
disclosure
in
our
Form
10-K
for
the
year
ended
December
31,
2010,
available
from
us
at
Nine
Greenway
Plaza,
Suite
300,
Houston,
Texas
77046.
You
can
obtain
these
forms
from
the
SEC
by
calling
1-800-SEC-0330.