W&T Offshore, Inc. Lehman Brothers CEO Energy/Power Conference New York, New York September 6, 2006

Transcription

1 W&T Offshore, Inc. Lehman Brothers CEO Energy/Power Conference New York, New York September 6, 2006

2 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, in addition to those discussed in Risk Factors in the prospectus supplement, the accompanying prospectus and in the documents that are incorporated by reference into the prospectus supplement, 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) uncertainties and difficulties associated with closing our pending Kerr-McGee transaction and the integration and operation of its properties thereafter. 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 information contained herein is a summary of certain information contained in the prospectus supplement and other periodic filings filed with the SEC. The information contained in such filings is incorporated herein by reference and qualifies the presentation in its entirety. We urge you to carefully review and consider the disclosures made in the prospectus supplement, and our reports filed with the SEC that attempt to advise interested parties of the risks and factors that may affect our business. 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, 2005, Form 10-Q for the period ending March 31, 2006, Registration Statement on Form S-3 filed on April 3, 2006 and Prospectus Supplement dated July 20, 2006, available from us at Nine Greenway Plaza, Suite 300, Houston, Texas You can obtain these forms from the SEC by calling SEC

3 W&T - Executing the Strategy Generate high return on equity focusing on GOM Continue to acquire high quality properties Competitors continue to divest GOM assets Enhance returns and growth rate through the drill bit Large prospect inventory generated from high held-by-production position Strong emphasis on conventional shelf; augmented with deep shelf and deepwater activities Maintain financial discipline Delever rapidly to capitalize on new opportunities Large executive and senior management equity stake 2

4 Company Strategy Remains the Same 2005 Roadshow Today Positions W&T for maximum growth Increases W&T s financial flexibility Acquisition currency for corporate and asset transactions Credibility 20 Months Later 5% reserve growth in 2005 Anticipated Production Growth in 2006 & 2007 $1 Bn bank debt arranged 1 st equity raise ever $1 Bn Kerr-McGee transaction $300+ MM follow on equity offering SEE ABOVE! 3

5 W&T versus Peers

6 Superior Long-Term Operating Performance CAGR: Reserve Growth CAGR: Production Growth % 25% 20% 15% 10% 5% 0% 22% 19% 14% 13% 9% % 15% 10% 5% 0% 14% 10% 9% 0% -5% -10% -15% -11% ATPG WTI BDE EPL ME CPE -5% -10% -6% -6% WTI CPE EPL BDE ME ATPG Avg Reserve Replacement Cost (1) 2005 Netback ($/Mcfe) (2) $/Mcfe $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $- $1.46 $1.70 $1.76 $2.26 $3.05 NA ATPG ME WTI BDE EPL CPE Source: John S. Herold 1. Reserve replacement cost is defined as the cost of reserves added through extensions & discoveries, revisions, improved recovery and purchases divided by the amount of reserves added in Mcfe terms. 2. Netback is defined as oil & gas revenue less production costs divided by production. 5 $/Mcfe $8.00 $7.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $- $7.21 $6.84 $6.75 $6.22 $5.87 $5.63 WTI EPL BDE CPE ATPG M E

7 W&T Profit Margins vs. Peers EBITDA-EBIT Margins Weighted Average ROACE Weighted Average (1) 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 78% 44% 72% 34% 69% 38% 56% % Gulf of Mexico Production (2) 100% 90% 80% 70% 60% 50% 40% 30% 24% 54% 52% 31% EBITDA EBIT WTI ME BDE EPL CPE ATPG 100% 100% 86% 86% 79% 74% 3% 6 60% 50% 40% 30% 20% 10% 0% 50% 35% % OIL Production (2) 20% 17% WTI BDE ME EPL CPE ATPG 20% 10% 10% 0% 0% WTI BDE CPE EPL ME ATPG CPE WTI EPL ATPG ME BDE 1. Calculation: Total EBIT/Weighted Average Book Capitalization for the five year period. EBIT adjusted for non-recurring items. Book Capitalization defined as total debt plus common and preferred equity. 2. Production through 06/30/ % 50% 40% 30% 20% 56% 40% 38% 8% 30% 29% 28% 1%

8 Report Card

9 Significant Transactions since 1999 Ability to overcome natural decline rates Strong acquire and exploit capabilities Acquisition (date) Reserves Acq'd 2003 YE Reserves 2004 YE Reserves 2005 YE Reserves Annual Compound Change (1) Vastar (1999) 18 Bcfe 64 Bcfe 59 Bcfe 49 Bcfe 17% Amoco (1999) 64 Bcfe 45 Bcfe 48 Bcfe 46 Bcfe (5.0%) EEX (2000) 46 Bcfe 32 Bcfe 32 Bcfe 28 Bcfe (9.0%) Burlington (2002) 120 Bcfe 137 Bcfe 140 Bcfe 168 Bcfe 10% ConocoPhillips (2003) 95 Bcfe 95 Bcfe 97 Bcfe 102 Bcfe 3% Results 343 Bcfe 373 Bcfe 376 Bcfe 392 Bcfe (1) Assume all transactions occur at 6/30 of the given year. 8

10 W&T Report Card Previous 5 Transactions Approximately 2X initial reserve bookings (Bcfe) Bcfe Initial Booked Reserves (Aggregate at Transaction) 343 Bcfe 290 Bcfe 392 Bcfe 290 Bcfe of Production from Transactions Booked Reserves (at 12/31/05) 682 Bcfe Total Net Estimated Recovery Includes 290 Bcfe of Production Since Transactions (at 12/31/05) Note: Excludes Kerr-McGee transaction. 9

11 W&T Report Card Previous 5 Transactions Value created from Major Transactions since 1999 ($ in millions) $2,250 Probable and Possible: $2,041 $1,750 Probable: 102 Bcfe Possible: 69 Bcfe $557MM PV-10 $346 MM PV-10 $1,250 PV-10 Value at 12/31/05 $750 $626 $250 Cumulative Revenue less Expenditures and Transaction Cost -$250 Aggregate Transaction Cost -$188 Note: Excludes Kerr-McGee transaction. PV-10 is based on SEC flat pricing of $57.75/Bbl and $9.73/Mcf as of December 31, 2005 and excludes P&A cost. 10

12 Significant Transactions since 1999 Transaction Fields Acq'd Reserves Acq'd Transaction Price ($MM) Acq. Multiple $/Mcfe 2005 Reserves Vastar 7 18 Bcfe $9.9 $ Bcfe Amoco 5 64 Bcfe $26.1 $ Bcfe EEX Bcfe $43.8 $ Bcfe Burlington Bcfe $52.3 $ Bcfe ConocoPhillips Bcfe $55.8 $ Bcfe Total Results Bcfe $187.9 $ Bcfe Kerr-McGee (1) Bcfe $1,339.0 $ Bcfe 1. Reserve data for Kerr-McGee properties as of September 30, 2005 based on natural gas and oil prices of $15.48/MMbtu and $63.00/Bbl respectively. Note: Reserves of 345 Bcfe adjusted for production of approximately 51 Bcfe and a closing price of $1,030.4 Bln would result in a multiple of $3.51 at closing. The estimated reserves quantities change over time due to factors such as revisions of previous estimates, production and extension discoveries and these factors are not included in this analysis. The Kerr-McGee reserves at closing are W&T internal estimates. 11

13 W&T Offshore Today

14 3 rd Largest GOM Shelf Acreage Position 177 Producing Fields with Working Interest 380+ MMcfe/day Production 67% Operating Production 2.0 million gross acres 68% held-by-production Metairie Mobile Viosca Knoll Houston Brazos Galveston High Island W. Cameron E. Cameron Vermilion Eugene Island Ship Shoal South Timbalier Grand Isle West Delta Main Pass S. Pass E. Add Mississippi Canyon Main Pass S. and E. Matagorda Island Ewing Bank Mustang Island East Breaks Garden Banks Green Canyon Atwater Valley W&T Offshore Kerr-McGee 13

15 Transaction Highlights Critical Mass and Scale Boosts proved reserves from 492 Bcfe as of 12/31/05 to approximately 800 Bcfe Diversity within the Gulf of Mexico W&T is approximately 1/3 each Western, Central and Eastern GOM Large Exploration Inventory / Significant Upside Potential Adds 90+ exploration prospects to a current inventory of 100+ Adds 4.4 Tcfe Net Unrisked Reserve Potential Increase Strategic Acreage Position Top-3 3 ranked acreage holder in GOM Shelf 14

16 Combined Company Proved Reserves WTI Reserves KMG Reserves Combined Reserves 35% 31% 32% 65% 69% 68% 492 Bcfe 345 Bcfe 837 Bcfe Proved Developed Proved Undeveloped Note: Reserve data for Kerr-McGee properties as of September 30, 2005 based on natural gas and oil prices of $15.48/MMbtu and $63.00/Bbl respectively. 15

17 Proved and Probable & Possible Reserves WTI Reserves KMG Reserves Combined Reserves 32% 34% 33% 33% 22% 27% 46% 33% 40% 1,078 Bcfe 1,000 Bcfe 2,078 Bcfe Proved Developed Probable Possible Note: Reserve data for Kerr-McGee properties as of September 30, 2005 based on natural gas and oil prices of $15.48/MMbtu and $63.00/Bbl respectively. 16

18 3 P & Net Unrisked Exploration Potential Reserves WTI Reserves KMG Reserves Combined Reserves 68% 73% 74% 32% 27% 26% 3,378 Bcfe 4,700 Bcfe 8,078 Bcfe 3 P Net Unrisked Note: Reserve data for Kerr-McGee properties as of September 30, 2005 based on natural gas and oil prices of $15.48/MMbtu and $63.00/Bbl respectively. Probable and Possible and Net Unrisked Reserves are internally estimated figures. 17

19 Combined Inventory of 200 Drilling Prospects Approximately 200 prospects with 25 prospects per year = 8 years of inventory Near-Term Includes Infield and High Potential for 2H 2006 and 1H Infield 104 High Potential 2H 2007 and beyond Inventory = 196 Total Prospects W&T Offshore Kerr-McGee 18

20 Combined Drilling Program

21 Exploration and Development Success W&T has registered high levels of success across all drilling and water depths 5 Year Exploration & Development ( Stand Alone) 2006 YTD Exploration & Development (Combined Company) 100% 80% 60% 81% 59% 67% 86% 100% 80% 60% 89% 4 for 4 75% 100% 2 for 2 78% 100% 2 for 2 40% 20% 100 for for 17 4 for 6 86 for % 20% 21 for 24 3 for 4 5 for 5 7 for 9 6 for 6 0% Total Wells Deepwater Wells Deep Shelf Wells Conventional Shelf Wells 0% Total Wells Deepwater Exploration Deep Shelf Exploration Conv Shelf Exploration Development Wells W&T Kerr-McGee 20

22 Near-Term High Impact Development Projects W&T Offshore Kerr-McGee Main Pass 185 Timing: 1Q 2007 Working Interest: 33% Initial Rate: 4.7 MMcfe/d Mobile Bay 824 Timing: 1Q 2007 Working Interest: 100% Initial Rate: 3.0 MMcfe/d South Timbalier 41 Timing: 3Q 2006 Working Interest: 40% Initial Rate: 15.8 MMcfe/d Grand Isle 3 Timing: 4Q 2006 Working Interest: 25% Initial Rate: 6.3 MMcfe/d Mobile Viosca Knoll West Cameron 295 Timing: 3Q/4Q 2006 Working Interest: 20% Expected Rate: 6.4 MMcfe/d Mustang Island Matagorda Island Eugene Island 205: Timing: Current Galveston Working Brazos Interest: 100% Current Rate: 45.3 MMcfe/d East Breaks High Island East Cameron 321 : Timing: 4Q 2006 Working Interest: 100% Initial Rate: 25.9 MMcfe/d W. Cameron E. Cameron Vermilion Garden Banks Eugene Island Queen of Hearts EB 949: Timing: 1Q 2007 Working Interest: 100% Expected Rate: 6.0 MMcfe/d Ship Shoal South Timbalier Green Canyon Ewing Bank Grand Isle West Delta Main Pass Mississippi Canyon Atwater Valley Main Pass S. and E. South Timbalier 299: S. Pass Timing: E. Add4Q 2006 Working Interest: % Expected Rate: 7.0 MMcfe/d Pluto MC 718: Timing: 3Q 2006 Working Interest: 49% Expected Rate: 23.2 MMcfe/d Cypress EW 989: Timing: 1Q 2007 Working Interest: 100% Expected Rate: 9.0 MMcfe/d 21

23 Production Timing Approximate Net Initial Rate (MMcfe/day) Project Name WI Q Q Eugene Island % 45.3 MMcfe/day Miss. Canyon 718 "Pluto" 49% 23.2 MMcfe/day South Timbalier 41 40% 15.8 MMcfe/day East Cameron % 25.9 MMcfe/day South Timbalier % 7.0 MMcfe/day West Cameron % 6.4 MMcfe/day Grand Isle 3 25% 6.3 MMcfe/day EW 989 "Cypress" 100% 9.0 MMcfe/day EW 949 "Queen of Hearts" 100% 6.0 MMcfe/day Main Pass % 4.7 MMcfe/day Mobile Bay % 3.0 MMcfe/day 22

24 East Cameron 321 WTI 100% Working Interest 7 Workovers (6 successful) and 5 sidetracks 12 Wells worked on resulted in 15 completions ready for production 3 Zones set up as selective 18 Total completions Forecasted Increase in Production from 9 net MMCFD to 35.8 net MMCFED Increase in Production December 2006 due to pipeline repair and rig activity Rig on location since September Rig down planned for September Net MMCFE/D Nov 06 - Jul-05 Jul-06 23

25 Cypress Deepwater Development Successful Exploration Well Drilled Oil Sands Completion and Tieback planned 1Q 2007 to Mahogany 100% WI 83.33% NRI DTR DTR Sand Sand Cris Cris S S Sand Sand MP3A MP3A Sand Sand MP3 MP3 Sand Sand 24

26 Eugene Island 205 Field EI 217 #C-4ST2 KK Sand KK Sand Acquired from Burlington % WTI Working Interest 4 Well Exploration Program C-1 ST2 Geologic Sidetrack in Progress Deep Shelf C-2 ST 7.6 Net MMCFD 229 Net BOPD Conv. Shelf C-3ST 3.2 Net MMCFD 45 Net BOPD Deep Shelf C-4ST 14.1 Net MMCFD 779 Net BOPD Deep Shelf GG Sand GG Sand Net Py 179 MD Net Pay 150 TVT EI 217 #C-2ST01 Net Pay = 75 TVD 3-D Seismic Courtesy of WesternGeco 25

27 Near-Term High Impact Exploration Projects W&T Offshore Kerr-McGee High Island 24: Timing: Current Working Interest: 25% Matagorda Island Brazos Net Predrill Unrisked Reserves Location Bcfe Deepwater 630 Deep Shelf 60 Conventional Shelf 60 Total 750 Galveston High Island W. Cameron West Cameron 295: Timing: Current Working Interest: 20% E. Cameron Vermilion Eugene Island Ship Shoal South Timbalier Ewing Bank King Lake: Timing: Current Working Interest: 100% Grand Isle West Delta Main Pass Mobile Eugene Island 205: Viosca Knoll Timing: Current Working Interest: 100% S. Pass E. Add Mississippi Canyon Main Pass S. and E. Healey GC 82: Timing: 4Q Working Interest: 100% Mustang Island Galveston Island 303: Timing: 4 Q 2006 Working Interest: 75% East Breaks LiveOak Ship Shoal 368 : Timing: 4Q 2006 Working Interest: 100% Garden Banks Green Canyon Demont GC 732: Timing: 1Q 2007 Working Interest: 100% BlackJack Atwater Valley EB 994: Timing: 2Q 2007 Working Interest: 100% 26

28 Ship Shoal 300 Former Kerr-McGee Property 75% - 100% Working Interest 12 In-Field Exploration Prospects Identified Shallow Reservoir Depth < 5000 Drilling to begin in late 2007/2008 following a detailed field study Additional workover/recomplete potential identified 27

29 Green Canyon 82 Healey 100% W&T Working Interest 2,400 feet Water Depth 2 W&T Operated wells to date- Healey #1, Healey #3 3 Primary Reservoirs Discovered 3 Secondary Reservoirs Discovered Additional drilling required to evaluate other exploratory prospects Development Plans currently being evaluated 28

30 Pluto MC 674 #3 M1:50 Sand 49% W&T Working Interest 2,800 feet Water Depth Mid-September first Production Lowest Known Gas Estimated Gas/Water 29

31 Conservative Reserve Bookings Up dip Potential Well Proved Reserve Bookings Gas Pay on water Oil Lowest known gas Down dip potential Water 30

32 Conservative Reserve Bookings A A Lowest Known Gas Amplitude Limit & Estimated Gas/Water Contact 3-D Seismic Courtesy of WesternGeco 31

33 Financials and Guidance

34 Combined Capital and Major Expense Program 2006E Program by Location 2006E Program by Category 11% 38% 42% 8% 51% 50% Conventional Shelf Deep Shelf Deepwater $ in MM % Conventional Shelf % Deep Shelf 58 11% Deepwater % Total % Development Exploration Other $ in MM % Development % Exploration % Other 46 8% Total % Note: Capital expenditures budget includes budgeted expense items such as workovers, and other non-capital items. Includes $10 MM in Kerr-McGee Capital Expense. 33

35 Average Daily Production E (MMcfe/d) Strong forecast year-over-year daily production growth (1)(2)(3) : 26% growth from E 50% growth from 2006E-2007E E 2007E production includes 47.4 MMcfe/d of hurricane deferral E for W&T stand-alone based on midpoint of Company s guidance of Bcfe for KMG represents an assumption of a 1/3 year of impact from the Kerr-McGee properties based on 165 MMcfe/d of production includes MMcfe/d of hurricane deferral E estimate of 459 MMcfe/d based on mean of 5 Wall Street equity research analyst reports. Dashed line represents range of 5 analyst estimates from MMcfe/d Hurricane Deferral 195 (1) 305 KMG Hurricane Deferral 234 W&T stand-alone (2) Wall St. Analyst Estimates (3)

36 Combined Company Year end Guidance Estimated Production WTI Stand Alone Full-Year 2006 Combined Company Full-Year 2006 Crude oil (MMbls) Natural gas (Bcf) Total (Bcfe) Daily Production (MMcfe/d) Operating Expenses ($ in millions,except as noted) Lease Operating Expense $ $82.3 $ $106.8 Gathering, transportation & production taxes $ $16.5 $ $21.3 General and administrative $ $43.0 $ $44.6 Income tax rate, % deferred 35%, 80% 35%, 80% 35

37 Amortization Schedule Senior Secured Debt $300 Million Senior Secured Revolving Credit Facility - Three Year Maturity Term Loan A Term Loan B Nov 24, 2006 $112,500,000 1Q07 $112,500, $ 1,500,000 2Q07 $112,500, $ 3,000,000 3Q07 $ 25,000, $ 3,000,000 4Q07 $ 25,000, $292,500,000 Total $387,500,000 Total $300,000,000 36

38 Commodity Hedging Schedule 3Q Q Crude Oil (Bbls/day) Swaps Volumes 1,800 2, Price $69.72 $ Collars Volumes ,300 2,800 Floor-Ceiling $ $76.40 $ $74.50 Natural Gas (MMBtu/day) Collars Volumes 23,000 33,000 24,000 14,000 Floor-Ceiling $ $13.10 $ $14.49 $ $16.80* $ $15.80* Approximate Mcfe/d 33,800 49,200 49,800 30,800 * Funded Collars 37

39 Reconciliation of Net Income to EBITDA The following table presents a reconciliation of our consolidated net income to consolidated EBITDA to Adjusted EBITDA: Six Months Year Ended December 31, Ended June 30, ($ in thousands) Net Income $ 48,204 $ 63,569 $ 2,049 $ 116,582 $ 149,482 $ 189,023 $ 94,296 Income taxes ,408 61,156 80, ,003 50,108 Net Interest expense 4,918 3,902 3,001 2,229 1,842 (1,601) (2,756) Depreciation, depletion, amoritization and accretion 29,775 65,293 89, , , , ,426 EBITDA $ 82,177 $ 132,764 $ 147,399 $ 323,659 $ 396,140 $ 472,258 $ 258,074 Non-cash change in commodity derivatives(before tax) ,490 Adjusted EBITDA $ 82,177 $ 132,764 $ 147,399 $ 323,659 $ 396,140 $ 472,258 $ 265,564 EBITDA is defined as net income plus income tax expense, net interest (income) expense, depreciation, depletion, amortization and accretion and non- cash expenses associated with unrealized changes in the fair market value of open derivative contracts. Although not prescribed under GAAP, we believe the presentation of EBITDA is relevant and useful because it helps our investors understand our operating performance and makes it easier to compare our results with those of other companies that have different financing, capital or tax structures. 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, as we calculate it, may not be comparable to EBITDA measures reported by other companies. In addition, EBITDA does not represent funds available for discretionary use. "Adjusted EBITDA" excludes the unrealized gain or loss related to open derivative contracts. Adjusted EBITDA excludes certain items that management believes affect the comparability of operating results. 38

40 W&T Offshore, Inc. Lehman Brothers CEO Energy / Power Conference New York, New York September 6, 2006