8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT PURSUANT

TO SECTION 13 OR 15(D) OF THE

SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported) March 9, 2010

W&T Offshore, Inc.

(Exact name of registrant as specified in its charter)

1-32414

(Commission File Number)

Texas	72-1121985
(State or Other Jurisdiction of Incorporation)	(I.R.S. Employer Identification No.)

Nine Greenway Plaza, Suite 300

Houston, Texas 77046-0908

(Address of Principal Executive Offices)

713.626.8525

(Registrant’s Telephone Number, Including Area Code)

N/A

(Former Name or Former Address, if Changed Since Last Report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01. Regulation FD Disclosure.

Tracy W. Krohn, Chairman and CEO of W&T Offshore, Inc. (the “Company”), is making a presentation discussing, among other things, the operations of the Company and the Company’s 2010 Drilling Program at the Raymond James 31st Annual Institutional Investors Conference on Wednesday, March 10, 2010 in Orlando, Florida. The audio presentation and accompanying slides will be broadcast live over the Internet. The webcast link can be accessed live and for replay by visiting the Company’s website at www.wtoffshore.com. The presentation materials are also furnished as an exhibit to this Form 8-K.

Item 9.01. Financial Statements and Exhibits

(d) Exhibits.

Exhibit No.	Description
Exhibit 99.1	W&T Offshore, Inc. - Raymond James 31st Annual Institutional Investors Conference Presentation

2

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	W&T OFFSHORE, INC. (Registrant)
Dated: March 9, 2010	By:	/s/ JOHN D. GIBBONS
		John D. Gibbons Senior Vice President and Chief Financial Officer

3

INDEX TO EXHIBITS

Exhibit No.	Description
Exhibit 99.1	W&T Offshore, Inc. - Raymond James 31st Annual Institutional Investors Conference Presentation

4

EX-99.1

Raymond James

Institutional Investors Conference

March 10, 2010

Exhibit 99.1

1

Company Highlights

Highlights

Reserve Data

2009

2008

Ticker

WTI (NYSE)

Proved Reserves (Bcfe)

371

491

Initial Public Offering

January 2005

Proved Developed Reserves (Bcfe)

284

334

Employees

286

Proved Developed %

76

%

68

%

Market Capitalization ($ in MMs)

(1)

$693

Oil and Liquids %

55

%

54

%

Insider Ownership (% of S. O.)

58

%

Key Financials ($ in MMs)

2009

2008

2007

Production

Revenue

$611

$1,216

$1,114

Average Daily Production (MMcfe)

220

+/-

Adjusted EBITDA

$342

$884

$820

Natural Gas %

53

%

Adjusted EBITDA Margin %

56

%

73

%

74

%

Operated Production % (net)

74

%

CAPEX

$276

$658

$362

Field Statistics (as of 12/31/09)

# of Producing Fields w/WI

82

(2)

Approx. Acreage (Gross/Net)

0.9 million/0.6 million

% Held-by-Production

79

%

(1) Market Capitalization as of March 5, 2010.

(2) Reflects sale of non-core fields (2nd & 4th quarter 2009), expired leases, and P&A program.

2

Key Investment  Considerations

•

Large acreage position in the Gulf of Mexico

•

Operating in the Gulf of Mexico for 26 years

•

Experienced staff

•

Strong cash flow & good liquidity

•

Balanced oil and gas reserve mix

•

Focused on growth opportunities at reasonable cost

–

Improving environment for acquisitions and joint venture

opportunities

–

Large prospect inventory

–

Focus on high impact opportunities

•

Improving operating metrics and margins

–

Lower LOE, ARO, DD&A rate, rig rates and overhead expenses

•

Strong Insider Ownership (~58%)

3

Proved Reserve Geographic Diversification

Our

geographic

diversity

provides

additional

protection

during

a

hurricane

4

What is great about the Gulf of Mexico

•

Great history of production and reserves

–

Reserves at deeper but virtually untapped zones, significant

upside potential (i.e. Davy Jones, Jack, etc.)

–

Highly prolific with multiple pay zones

–

Reserve to production profile is consistent

–

Established infrastructure on shelf

•

Attractive reservoir characteristic

–

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)

5

Our Historical Gulf of Mexico Focus

•

Operating successfully in the Gulf of Mexico for 26

years

–

10 year exploration drilling success rate of 78%

–

10 year development drilling success rate of 90%

–

Established infrastructure allows for accelerated cash flow

•

Inventory of 160 drilling prospects

–

WTI holds interest in about 82 fields -

spread across the GOM

–

Significant  reserve upside potential in deeper zones

–

Extensive seismic, production and log data

•

Active M&A and joint venture market

•

Costs historically adjust quickly to commodity prices

–

Late 2008 & first half of 2009 was exception, partially due to

Hurricane

6

Accomplishments in 2009

•

77% success in 2009 exploration and development

drilling program, including successfully drilling eight

of ten exploration wells and two of three development

wells

•

Asset retirement obligations decreased $199.1 million

via dispositions and cost revisions

•

LOE decreased $25.8 million for the year through

divestitures of non-core assets and cost reduction

initiatives ($2.15/Mcfe in 2009 vs. $2.35/Mcfe in 2008)

•

Hedged approximately 20 Bcfe

of 2010 production

•

Returned to profitability

•

Maintained liquidity without dilution

7

2010 Goals & Objectives:

Focusing on Growth and Profitability

•

Grow reserves

–

Initial drilling program of 10 wells –

187 Bcfe

net unrisked

most

likely reserves

–

Pursue acquisitions with proved reserves and exploitation

opportunities

–

Drill high impact wells

–

63% increase in cap-ex program

•

Increase production

–

2009 & 2010 drilling program, including potential joint ventures

–

Recompletions & Workovers

–

Potential acquisition of producing properties

8

2010 Goals & Objectives:

Focusing on Growth and Profitability –

Cont’d

•

Cost management

–

LOE controls

–

Possible divestiture on non-core properties

–

Committed to competitive F&D metrics

•

Improve EBITDA margins closer to historic levels

–

Reducing costs of goods & services in line with commodity prices

–

New hedging program

9

Reserve Growth Opportunities

•

Acquisitions

–

Prices have declined substantially since 2008

–

Deal flow is accelerating

–

Experienced A&D team

–

Evaluating onshore (long life reserves) and offshore 

(deepwater)

–

Aggressively pursue acquisitions in the current environment

•

Drilling Projects

–

Large inventory of conventional shelf projects

–

Joint ventures

–

Focus on high impact exploration projects

–

Onshore

10

2010 Capital Expenditures Budget

•

$450 million budget is 63% higher than in 2009

•

$153 million is allocated to:

–

Ten wells, including nine exploration and one development

–

Well recompletions, facilities capital, seismic and leasehold

•

Remainder of budget has been allocated to:

–

Acquisitions

–

Joint ventures or third-party drilling prospects

–

Drilling other prospects within our 160 well prospect

inventory

11

Ewing

Bank

Proposed 2010 Drilling Program

Viosca

Knoll

S. Pass

E. Add

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

West

Delta

Grand

Isle

Main

Pass

W.

Cameron

Exploration

MP 98 -

#1

WI: 100%

Shelf

MP 108 –

E3

WI: 67%

Shelf

Bay Marchand

#2

WI: 30%

Shelf

VK 734 A-4

WI: 100%

Shelf

Non-commercial

HI 129 #16 ST2

WI: 10%

Shelf

Development

Plus: Four additional exploration wells,

which includes one onshore well and

one deepwater well

MP 283 –

A2ST4

WI: 89%

Shelf

Main

Pass

S. and E.

12

Strategic Budgeting with a

Long-Term Focus

•

We drill within cash flow

•

Focus on maintaining

liquidity

•

Reduce capital budget when

service costs are high and

commodity prices are low

•

Maintain a disciplined

investment strategy

•

In 2010, we expect to spend

63% more on capital

expenditures over 2009 due

to better operating metrics

$276

$658

$361

$306

$589

$17

$1,062

$117

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

2005

2006

2007

2008

2009

Drilling CapEx

Acquisition CapEx

Capital Expenditures

($ in millions)

13

Proved Reserves by Year

•

Reserves & production

growth typically track capital

spending levels

•

Negative pricing & adverse

economic conditions offset

drilling successes and

acquisitions

•

New SEC rules reduced

reserves in 2009

*

Includes

157.5

Bcfe

of

downward

revisions,

most

of

which

is

related

to

pricing. 

**

Includes

48.2

Bcfe

reduction

due

to

SEC

rule

changes.

215.9

401.2

332.8

227.9

165.8

275.6

334.0

306.0

263.3

205.2

$323.0

$361.2

$774.9

$276.1

$1,650.8

0.0

200.0

400.0

600.0

800.0

2005

2006

2007

2008

2009

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

Oil & NGLs

(Bcfe)

Natural Gas (Bcf)

Total CapEx

491.5

735.2

491.1*

638.8

371.0**

215.9

401.2

332.8

227.9

165.8

275.6

334.0

306.0

263.3

205.2

$323.0

$361.2

$276.1

$1,650.8

0.0

200.0

400.0

600.0

800.0

2005

2006

2007

2008

2009

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

Oil & NGLs

(Bcfe)

Natural Gas (Bcf)

Total CapEx

491.5

735.2

491.1*

638.8

371.0**

$774.9

14

Production Profile

•

2010 production guidance of

60 to 80 BCFE is based on

the initial 7 well budget and

$150 million cap-ex program

–

not full $450 million budget

•

Second half of 2008 and 2009

was focused on preserving

capital and lower cost

projects with high impact

such as workovers

and

recompletions

•

Extensive 2010 workover

and

recomplete program planned

71.1

99.2

(1)

(2)

126.5

Oil & NGLs

(Bcfe)

Natural Gas (Bcf)

(3)

97.9

94.8

(1)  2005 Production does not include17.4 Bcfe of deferral caused by Hurricanes Katrina and Rita

(2)  2006 Production does not include 7.8 Bcfe of deferral caused by Hurricanes Katrina and Rita

(3)  2008 Production does not include 21.7 Bcfe of deferral caused by Hurricanes Gustav and Ike

15

Proved & 3P

Reserves Mix

PDP

43%

PDNP

33%

PUD

24%

2009

–

Proved

Reserves

Proved

40%

Probable

16%

Possible

44%

2009

-

3P

Reserves

Oil

Gas

Total

Mbo

MMcf

MMcfe

PDP

12,667

86,561

162,564

43%

PDNP

11,041

54,714

120,963

33%

Total Proved Dev.

23,709

141,275

283,527

PUD

10,494

24,482

87,445

24%

Total Proved

34,203

165,757

370,972

100%

Reserve Mix

55

%

45

%

100

%

Oil

Gas

Total

Mbo

MMcf

MMcfe

Proved

34,203

165,757

370,972

40%

Probable

13,043

62,201

140,458

15%

Possible

37,048

183,520

405,805

44%

16

Strategic Acquisition Criteria

Opportunistic Approach

•

Properties generating cash flow

–

Strong current production rates

•

Financeable 

–

Large portion of reserve base is proved developed and can

be financed

•

Identified upside

–

Properties have undrilled prospects

–

Contiguous acreage to existing heritage properties

–

Undeveloped lease blocks / acreage

•

Overlooked assets

–

Workover

and recompletion opportunities

•

Adding staff to focus on deepwater and long life

reserves

17

Prudent Investment Strategy

•

Proven, experienced and expanding A&D team

•

Improving transaction market

(1)

–

Domestic E&P transactions of $5.8 billion in 2009 compared

to $26.6 billion in 2008

–

Deals of $7.8 billion done thus far in 2010

–

Transaction prices have fallen from $22.92/Boe in the third

quarter of 2008 to $13.67/Boe in the first quarter of 2010

•

Evaluating multiple basins

•

Disciplined investment approach

(1) Source: Bloomberg and other industry data.

18

Adjusted EBITDA

Margins Improving

•

Cost of goods & services

have historically tracked with

commodity prices in the

GOM

•

From 2000 thru 2007, Adj.

EBITDA margins averaged

79% despite variable

commodity prices

•

In 2009, margins were

squeezed by high service

costs and low commodity

prices

•

Hurricane Ike caused service

costs to remain high

•

Margin improvement in latter

part of 2009 is expected to

continue in 2010

19

W&T Liquidity -

Opportunities

•

Reduced debt by $200 million and ARO by $200

million

•

Cash balance at February 25, 2010 ~ $250 million

•

Revolver availability at February 25, 2010 = $262

million with $405 million borrowing base

–

We redrew the revolver to generate interest income that

helps offset the effects of the interest rate swap

20

Key Drivers

•

Large acreage position

•

Operating in the Gulf of Mexico for 26 years

•

Strong cash flow & liquidity

•

Focus on achieving sustainable production and

reserve growth

•

Improving operating metrics and margins

•

Growing staff to increase investment opportunities

•

Strong insider ownership

•

Solid and well positioned for the future

21

The

following

table

presents

a

reconciliation

of

our

consolidated

net

income

to

consolidated EBITDA to Adjusted 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 and the unrealized gain or loss related to our derivative contracts.  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.

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

($ in thousands)

Net income

48,204

$

63,569

$  

2,049

$     

116,582

$ 

149,482

$

189,023

$  

199,104

$

144,300

$

(558,819)

$

(187,919)

$

Income taxes (benefit)

--

--

52,408

61,156

80,008

101,003

107,205

71,459

(269,663)

(74,111)

Net interest expense (income)

4,918

3,902

3,001

2,229

1,842

(1,601)

11,261

30,684

21,337

39,245

Depreciation, depletion,

amortization and accretion

29,775

65,293

89,941

143,692

164,808

183,833

337,627

532,910

521,776

342,537

Impairment of oil and natural gas

properties

--

--

--

--

--

--

--

--

1,182,758

218,871

EBITDA

82,177

132,764

147,399

323,659

396,140

472,258

655,242

779,353

897,389

338,623

Loss on extinguishment of debt

--

--

--

--

--

--

--

2,806

--

2,926

Unrealized derivatives loss (gain)

--

--

--

--

--

--

(13,476)

37,831

(13,501)

693

Adjusted EBITDA

82,177

$

132,764

$

147,399

$ 

323,659

$ 

396,140

$

472,258

$  

641,766

$

819,990

$

883,888

$  

342,242

$  

Year Ended December 31,

Reconciliation of Net Income to EBITDA

22

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, 2007, 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.

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

Appendix

25

2010 Guidance and Capital Budget

Estimated Production

(1)

Full-Year 2010

Crude oil (MMBbls)

4.6 –

6.2

Natural gas (Bcf)

32.4 –

42.8

Total (Bcfe)

60.0 –

80.0

Operating

Expenses

($

in

millions)

Full-Year

2010

Lease operating expenses                                       

$168 –

$206

Gathering, transportation & production taxes

$14 –

$18

General and administrative

$43 –

$47

(1)

Includes

the

build

up

associated

with

the

seven

wells

in

the

original

2010

Budget.

26

Hedging Strategy & Schedule

•

The Company has hedged 11.9 Bcf

of its 2010 natural gas production and

1.27 MMBbls

of its 2010 oil production

–

Hedges were put in place to augment the borrowing base and the 2010 drilling budget

–

Natural

gas

production

is

hedged

with

floors

as

low

as

$5.00

and

ceilings

as

high

as

$9.40

–

Crude

oil

is

hedged

with

floors

as

low

as

$65.00

and

ceilings

as

high

as

$90.35

–

We

also

have

entered

in

a

natural

gas

swap

for

2010

for

730,000

MMBtu

or

2,000

MMBtu/day

(1)

Includes 2,000 MMBtu/day for Swaps

Note: Daily volumes may not foot to notional quantities due to rounding.

1Q 2010

2Q 2010

3Q 2010

4Q 2010

Natural Gas (MMBtu/day)

Collars

Volumes

51,056

34,648

16,799

19,911

Weighted Avg

Price

$5.00 -

$5.94

$5.00 -

$6.09

$5.00 -

$6.60

$5.00 -

$8.35

Crude Oil (Bbls/day)

Collars

Volumes

4,750

4,250

2,261

2,645

Weighted Avg

Price

$69.85 -

$81.57

$69.84 -

$83.82

$69.84 -

$85.51

$69.74 -

$86.22

Approximate Mcfe/d

(1)

81,556

62,148

32,364

37,782