W&T Offshore (WTI) 8-K Regulation FD Disclosure

W&T Offshore, Inc.

Pritchard Capital Partners

ENERGIZE 2008

San Francisco, California

January 10, 2008

Exhibit 99.1

1

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, 2006, 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.

2

Company Highlights

Market capitalization as of January 4, 2008

Reserve Data

(as of 12/31/06)

Proved Reserves (Bcfe)

735

Proved Developed Reserves (Bcfe)

479

Proved Developed %

65%

Oil and Liquids %

45%

Highlights

Field Statistics (as of 12/31/06)

Ticker

WTI (NYSE)

# of Producing Fields w/WI

158

Initial Public Offering

January 2005

Approx. Acreage (Gross/Net)

2.0 million/1.1 million

Employees

295

% Held-by-Production

70%

Market Capitalization ($ in MMs)

$2,352

Insider Ownership (% of S. O.)

65%

Key Financials ($ in MMs)

2006

9 months

ended

9/30/2007

Production - as of 12/15/07

Revenue

$800

$774

Average Daily Production (MMcfe)

350 +/-

Adjusted EBITDA

$642

$567

Natural Gas %

58%

Adjusted EBITDA Margin %

80%

73%

Operated Production % (net)

67%

CAPEX

$589

$277

3

W&T’s Business Strategy

Cash flow returns and generation is our top priority

Increase reserves and revenue through the drill bit and by acquisition

Continued focus on offshore Gulf of Mexico

Conventional shelf –

primary focus

Deep Shelf and Deepwater –

secondary focus

Numerous acquisition opportunities exist today

Competitors continue to divest GOM assets

Assets are not leaving basin, just changing hands

Acreage will be King!

Many companies have “left or are leaving”

the shelf

Held by production acreage is best

Maintain financial discipline

4

Winning Acquisition Strategy

1.

Cash Flow

Key to

our

successful

acquisition

strategy

is

our

ability

to

target

under-exploited

assets

KMG has strong production rates, including

several behind pipe, workover projects identified

68% of reserves were proved developed

Bank group underwrote the entire $1.34B

transaction

Five years of drilling prospects identified

Many prospects “leftover”

from KMG’s Westport

transaction

Many prospects identified by independent

consulting firm

Minimal staff and expenditures for 1 million acres

= under-exploited assets!!

Key Acquisition Factors

Kerr-McGee Example

2.

“Bank-ability”

3.

Identified Upside

4.

Neglected properties

5

Transaction History

1. Assume all transactions occur at 6/30 of the given year.

Ability to overcome natural decline rates

Strong acquire and exploit capabilities

Cumulative production through 2006 was 346 Bcfe

Acquisition (date)

Reserves

Acq'd

2003 YE

Reserves

2004 YE

Reserves

2005 YE

Reserves

2006 YE

Reserves

Annual

Compound

Change  

(1)

Vastar (1999)

18 Bcfe

64 Bcfe

59 Bcfe

49 Bcfe

46 Bcfe

13%

Amoco (1999)

64 Bcfe

45 Bcfe

48 Bcfe

46 Bcfe

41 Bcfe

(6%)

EEX (2000)

46 Bcfe

32 Bcfe

32 Bcfe

28 Bcfe

19 Bcfe

(12%)

Burlington (2002)

120 Bcfe

137 Bcfe

140 Bcfe

168 Bcfe

137 Bcfe

3%

ConocoPhillips (2003)

95 Bcfe

95 Bcfe

97 Bcfe

102 Bcfe

92 Bcfe

0%

Results

343 Bcfe

373 Bcfe

376 Bcfe

392 Bcfe

335 Bcfe

Kerr-McGee

247 Bcfe

247 Bcfe

--

(                      

Net of Production                     )

6

Probable and Possible:

499 Bcfe

-$1,000

-$750

-$500

-$250

$0

$250

$500

$750

$1,000

$1,250

$1,500

Acquisitions Report Card 

Aggregate

Transaction

Cost

Cumulative

Revenue

less

Expenditures

and

Transaction

Cost

PV-10 Value

at 12/31/06

Note: Excludes Kerr-McGee transaction.

Value

created

from

5

Major

Transactions

since

1999         

($ in millions)

Probable and Possible:

Probable:  102 Bcfe

$423 MM PV-10

Possible:   126 Bcfe

$424 MM PV-10

-$188

$907

-$1,000

-$750

-$500

-$250

$0

$250

$500

$750

$1,000

$1,250

$1,500

$1,386

Kerr-McGee from close to 09/30/07

($ in millions)

PV-10 Value

at 12/31/06

-$1,062

Cumulative

Revenue

less

Expenditures

and

Transaction

Cost

-$819

$746

PV-10 Value

at 12/31/06

Aggregate

Transaction

Cost

Approximate Revenues and Costs at 9/30/07

•

93 Exploration and Development Wells Drilled

•

3 Exploration and Development Wells Drilled

•

“Harvesting Cash Flow”

$243 MM of

CF produced

since close

7

Higher Long-Term Margins

79%

72%

69%

61%

54%

48%

43%

35%

38%

17%

14%

12%

0%

20%

40%

60%

80%

WTI

CPE

BDE*

ATPG*

SGY

EPL*

2002-2006 EBITDA-EBIT Margins Weighted Average

EBITDA

EBIT

$8.40

$8.07

$4.31

$4.00

$3.50

$5.33

$6.16

$8.23

73%

80%

81%

79%

77%

78%

79%

80%

$0.00

$2.00

$4.00

$6.00

$8.00

2000

2001

2002

2003

2004

2005

2006

YTD

2007

0%

20%

40%

60%

80%

100%

Avg. Realized Price

Adj. EBITDA Margin

W&T Offshore High EBITDA Margins

* Successful efforts accounting

Reserves and Production Overview

9

Ship

Shoal

Green Canyon

Garden Banks

Vermilion

W.

Cameron

High

Island

Galveston

Brazos

West

Delta

Mustang

Island

East Breaks

Matagorda

Island

Eugene

Island

South

Timbalier

Ewing

Bank

Atwater Valley

Mississippi Canyon

Grand

Isle

E.

Cameron

S. Pass

E. Add

Mobile

Main

Pass

Main

Pass

S. and E.

Viosca Knoll

Proved Reserve Geographic Diversification

Houston

Metairie

> 650 Miles

Western

Central

Eastern

Proved Developed

East

23%

West

40%

Central

37%

Total Proved

Central

51%

East

20%

West

29%

Our geographic

diversity

provides

additional

protection

during

a

hurricane

10

12.4

28.4

39.4

52.8

53.3

46.6

60.4

11.4

13.9

14.8

26.2

29.1

24.5

38.8

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

2000

2001

2002

2003

2004

2005

2006

2007E

Oil & NGLs

Gas

4Q

28.8 –

34.8

Actual

3Q –

28.9

23.8

42.3

54.2

79.0

82.4

Production growth

1

2005 production does not included 17.4 Bcfe of deferral caused by severe hurricanes.

2

2006

Production

does

not

included

7.8

Bcfe

of

deferral

remaining

from

severe

hurricanes

in

2005.

71.1

99.2

(1)

(2)

25% production

growth at mid-point

of range for 2007

Actual

1Q –

32.1

Actual

2Q –

31.2

Full-Year

Guidance

121 -

127

11

45%

40%

40%

35%

33%

32%

23%

0%

10%

20%

30%

40%

50%

SGY

WTI

ATPG

EPL

ME

CPE

BDE

% Oil / Liquids Production Year-to-Date Through 09/30/07

Mix of Production

Drilling Overview

13

Development Drilling

6

6

6

2

2

3

7

8

1

1

1

1

100%

86%

100%

86%

100%

100%

67%

86%

0

1

2

3

4

5

6

7

8

9

2000

2001

2002

2003

2004

2005

2006

2007

2008E

Successful

Non-Commercial

% Successful

2000 –

2007 Overall Drilling success: 40 of 44, 91% success rate

14

18

10

17

2

2

5

7

6

5

6

21

19

1

11

100%

75%

83%

86%

77%

75%

666%

100%

0

5

10

15

20

25

30

35

40

45

50

2000

2001

2002

2003

2004

2005

2006

2007

2008E

Successful

Non-Commercial

% Successful

Exploration Drilling

1999

EEX, Vastar, Amoco

Transactions

2002

Burlington

Transaction

2006

Kerr-McGee

Transaction

2000-2007 Overall Drilling success: 102 of 130, 78% success rate

Recent Events

16

Recent Asset Acquisition –

SS349 “Mahogany

First commercial field in the subsalt

play in the GOM

5 productive horizons below salt at

depths as deep as 17,000 feet 

Purchased 25% interest as part of

BP/Amoco transaction in 1999

Purchased additional 34% interest

with ConocoPhillips transaction in

2003

Became operator in Dec. 2004

Entered into PSA to purchase

remaining interest in Dec. 2007

Gross cumulative production of

19,600 MBO and 40 Bcf

84% oil reserves on 12/31/06

Currently producing 1,500 bbls

and

2,400 Mcf, gross per day

17

W&T has budgeted $800 million for capital in 2008

2008 budget represents a 77% increase over 2007

The budget includes 44 exploration wells and 6 development wells

40 Conventional Shelf wells

10 Deep Shelf or Deepwater wells

We anticipate fully funding the 2008 budget from internally generated cash flow

At 3Q 2007, we spent $162.3MM on Development activities and $71.6MM on

Exploration activities and $43.4MM on seismic, leasehold costs and other capital

items

2008 Capital  Expenditures Program

($ in millions)

Exploration

330

$      

41%

185

$         

41%

252

$      

43%

Development

450

56%

236

52%

302

51%

Seismic

20

3%

32

7%

35

6%

Total Capital Budget

800

$      

100%

453

$         

100%

589

$      

100%

Revised 2007 Budget

2008 Budget

2006A

2007 Exploration & Development  Results

+

Near-Term Drilling Program

19

Ship

Shoal

reen

Canyon

Vermi

n

W.

Camer

Galves

High

Island

Brazos

Mustang

Island

East Breaks

Matagorda

Island

Eugene

Island

South

Timbalier

Atwater Valley

Mississippi Canyon

Grand

I   

E.

Cameron

Ma 

Pass

Main

Pass

S. and E.

Operations Update

Drilled and Online

Currently drilling or to be drilled

GREEN CANYON 82 *

SOUTH

TIMBALIER

41

B-3

–

KMG

Online 4Q 2007

HIGH ISLAND 24L

Online 4Q 2007

WEST CAMERON 181 –

KMG

Online 2Q 2007

HIGH ISLAND AREA *

1 well drilling

VERMILION 331

Online 2Q 2007

HIGH ISLAND 22 -

KMG

Online 1Q 2007

SHIP SHOAL AREA –

KMG *

2 wells drilling

* Indicates rig or multiple rigs on location

Completed drilling but not online

SOUTH TIMBALIER AREA (OBO) *

1 well drilling

SHIP SHOAL AREA -

KMG

2 Wells online Dec 2007

MAIN PASS AREA  

1 well to be drilled

MAIN  PASS AREA -

KMG

1 non-commercial well

drilled

in

4Q

2007

Viosca Knoll

20

Rig Overview

Rig Rates

$0

$50

$100

$150

$200

$250

$300

$350

3rd Gen Semis

>300' Cant. Jackups

250' Slot Jackups

Submersibles

GOM Jack-Up Supply/Demand

Sources: Jefferies, ODS-Petrodata

21

Green Canyon 82 –

Healey Overview

100% Working Interest to W&T

3 W&T wells drilled to date

Not online or producing

Healey #1 (2006)

Healey #3 (2006/2007)

Healey #4 (TD Dec 2007)

5 Primary Reservoirs

9,450’

Oil

11,300’

Oil

10,900’

Gas

12,250’

Oil

11,200’

Gas

For

primary

reservoirs

only

-

3P

Total

–

260

Bcfe

Healey #4 –

lower two objectives successful

Potential Development options are currently

being evaluated pending geological and

engineering analysis

7 Additional Prospects have a total unrisked

exploratory potential of about 219 Bcfe

Seismic Courtesy of PGS

#1

#4

Drilled

“From Evaluation to Implementation …”

Kerr-

McGee Prospects

23

Seismic Coverage

Goal is to obtain a continuous 3-D database covering all W&T properties

Recent new 3-D seismic acquisition –

as indicated in the green shaded areas

660 blocks of SEI 3-D across offshore Texas

68 blocks of WesternGECO/GPI across Mass Pass

New seismic is already showing results on W&T and KMG properties

5,400 blocks of 3-D

coverage

Over 35 million acres of

seismic data

24

Ship Shoal Area

Ship Shoal Program 1

Approximately 45% W&T working

interest

4 Drilling locations proposed for 2008

Most drilled from existing platform with

existing production facilities

Total net unrisked exploration potential

of 20 Bcfe

Ship Shoal Program 2

Large acreage position covering Deep

Shelf exploration and Salt Dome flank

prospects

Potential exploration drilling in 2008-

2009

SS219

SS256

25

Ship Shoal 300 Area

Former Kerr-McGee Property

W&T operated with 75% Working

Interest

250-300 Feet Water Depth

7-10“In-Field”

Exploration

Prospects Proposed 2008

Moderate Drilling Depths: 2300’

TVD to 12,200’

TVD

Drilling began Sept 2007

SS 300 A-1ST successful

SS 300 A-3ST successful

Currently drilling 2 exploration

wells

Pre-drill Total Net Unrisked

Exploration Potential of 70 Bcfe

Most drilled from platforms with

existing production facilities

26

Main Pass/Viosca Knoll Area

Recent new state-of-the-art 3-D seismic

acquisition

68 blocks acquired over concentration of

former Kerr-McGee Main Pass acreage

6-9 well program in 2007/2008, most drilled from platforms with existing production facilities

Total Net

Unrisked

Exploration

Potential

–

154

Bcfe

1 non-commercial well at Main Pass 162 A-3

Viosca Knoll

27

Ship

Shoal

Green Canyon

Garden Banks

Vermilion

W.

Cameron

High

Island

Galveston

Brazos

West

Delta

Mustang

Island

East Breaks

Matagorda

Island

Eugene

Island

South

Timbalier

Ewing

Bank

Atwater Valley

Mississippi Canyon

Grand

Isle

E.

Cameron

S. Pass

E. Add

Mobile

Main

Pass

Viosca Knoll

2008 Anticipated Drilling Locations

Houston

Metairie

•

Unrisked Potential: 848 Bcfe

•

Risked Potential: 445 Bcfe

•

27 of 50 Prospects from Kerr-McGee

Unrisked Res. (Bcfe)

39 Conv

Shelf

371

9 Deep Shelf

315

2 Deepwater              162

Main

Pass

S. and E.

28

W&T Liquidity -

Opportunities

Exploratory

Drilling

Asset

Acquisition

Corporate

Acquisition

Debt

Repayment

Special

Dividend

(1) 3Q 2007 adjusted EBITDA held flat for 2007E and annualized for 2008 projected for illustrative purposes only   (2) Does not include cash interest or taxes

Free Cash Flow

($ in millions)

2007E

2008

Projected

Cash on hand @ 9/30/2007 and projected cash

187

$        

192

$        

Less: Remaining Non-Discretionary items

(73)

-

Less: Remaining Discretionary items

(113)

-

Less: 2008 Budget

-

(800)

Less: Special one-time cash dividend (1/11/2008)

-

(30)

Less: Acquisition of SS349/359 (2Q 2008)

-

(116)

Cash less Capital and other

1

(754)

Plus: Adjusted EBITDA

191

764

Free Cash Flow

192

$        

10

$          

Undrawn

revolver @ 11/07/2007

500

$        

500

$        

1

2

29

Key Drivers

High cash-on-cash return

Superior Metrics vs. Peers

W&T trading at a discount to NAV

Proven Track-Record of Acquiring and Exploiting

Opportunity and size of Future Transactions

Large inventory of prospects

Favorable Oil:Gas Mix in Volatile Times

Acceptable Debt Levels

Sufficient Liquidity

Appendix

31

Well

Non Proved         

Down dip potential

Up dip

Potential

Proved

Reserve

Bookings

Proved Reserve Bookings Example

Lowest known gas

32

Proved Reserve Bookings -

Pluto MC 718

3-D Seismic Courtesy of WesternGeco

33

Pluto MC 718 #3 M1:50 Deepwater Sand

Example of limited proved reserve bookings

Initial production in mid-September 2006

34

High Island 22

High Island 22

100% W&T working interest

1   well drilled on former Kerr-McGee property

Successfully drilled and completed B-3ST in

January 2007

Current rate of 6.0 MMcfe/day gross

st

35

Barge

Platform

Specialty

Jack-Ups

Specialty J/U

Semi-Submersible

Drillship

<2000 HP

<1000 HP

Submersible

Workover

450' I. L.  Cantilever

2 Gen

<5000'

>2000 HP

>1000 HP

150' Mat Cantilever

Tarzan

3 Gen

>5000'

200' - 250' Mat Slot

Gorilla

4 Gen

200' - 300' I. L.  Cantilever

Super Gorilla

5 Gen

200 - 300' Mat Cantilever

300' Independent Leg Slot

250' Slot Rig

300' - 350' Slot

350' + Slot

Operated Rig Analysis

Types of rigs necessary for proposed 2008 drilling program.

Listed below are the type of rigs necessary to complete our 2008

drilling

program of approximately 50 wells

Rig types by level of complexity

36

High Island 24

High Island 24 Area

25% W&T working interest

40 feet of water depth

Initial discovery well drill Sept 2006

500’

gross pay-

300’

net gas

Initial

production

test

–

49

MMcfe/day

gross

Successful offset well completed in March 2007

470’

gross

pay

–

200’

net

gas

Initial

production

test

–

52

MMcfe/day

gross

Current rate 9 MMcfe/d

HI 24

HI 8

HI 9

HI 25

HI 23

HI 31

HI 32

HI 33

HI 24

HI 8

HI 9

HI 25

HI 23

HI 31

HI 32

HI 33

HI 24

HI 8

HI 9

HI 25

HI 23

HI 31

HI 32

HI 33

37

100% GWI in S/L 17993 #1 ST Terrebonne Parish, LA

8 Feet Water Depth

#1ST reached a Total MD of 18,553 feet on 10/10/06

The Well Logged 42’

Net Gas in the Big 2 Sand

10 to 15 Bcfe 3P estimated

WTI’s Deepest Operated Production in the GOM

First Production –

4Q 2007

18.0 MMcfe/d net estimated production

Current production is 9.5 MMcfe/d

Bay Junop Field

38

Reconciliation of Net Income to EBITDA

The following table presents a reconciliation of our consolidated net income to

consolidated EBITDA to Adjusted EBITDA:

We define EBITDA as net income plus income tax expense, net interest expense (income), and depreciation, depletion,

amortization and accretion.  We believe the presentation of EBITDA and Adjusted EBITDA 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.  Adjusted

EBITDA excludes the loss on extinguishment of debt and the unrealized gain or loss related to our open derivative contracts. 

Although not prescribed under generally accepted accounting principles, we believe the presentation of EBITDA and Adjusted

EBITDA are relevant and useful because 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 flows 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.

Nine Months

Ended

September 30,

2000

2001

2002

2003

2004

2005

2006

2007

($ in thousands)

Net income

48,204

$

63,569

$  

2,049

$    

116,582

$

149,482

$

189,023

$  

199,104

$

94,890

$           

Income taxes

--

--

52,408

61,156

80,008

101,003

107,205

48,988

Net interest expense (income)

4,918

3,902

3,001

2,229

1,842

(1,601)

11,261

26,149

Depreciation, depletion,

amortization and accretion

29,775

65,293

89,941

143,692

164,808

183,833

337,627

373,358

EBITDA

82,177

$

132,764

$

147,399

$

323,659

$

396,140

$

472,258

$  

655,242

$

543,385

$         

Loss on extinguishment of debt

--

--

--

--

--

--

--

2,806

Unrealized derivatives loss (gain)

--

--

--

--

--

--

(13,476)

21,360

Adjusted EBITDA

82,177

$

132,764

$

147,399

$

323,659

$

396,140

$

472,258

$  

641,766

$

567,551

$         

Year Ended December 31,

W&T Offshore, Inc. (NYSE: WTI)

Nine Greenway Plaza

Suite 300

Houston, TX  77046

Main line -

713-626-8525

Fax -

713-626-8527

Investor Relations -

713-297-8024

www.wtoffshore.com

www.investorrelations@wtoffshore.com