![]() 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. |