IPAA Oil & Gas Investment Symposia April 3, 2017 Creating Value in the Gulf of Mexico
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, 2016, 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
Premium Assets in the Gulf of Mexico NYSE: WTI SEC Case NYMEX Case Proved reserves (at 12/31/16): 1P 74.0 MMBoe 77.6 MMBoe 2P 113.0 MMBoe 117.3 MMBoe Oil & liquids % of proved reserves 55% 56% PV-10 (NYMEX only) $1.2 Billion Deepwater Gulf of Mexico ~ 260,000 gross acres (~105,000 net acres) ~ 46% of daily production of 41,980 Boe/d (1) 1P reserves of 26.2 MMBoe 2P reserves of 43.0 MMBoe Substantial upside with existing acreage Gulf of Mexico Shelf ~ 490,000 gross acres (~350,000 net acres) ~ 54% of daily production of 41,980 Boe/d (1) 1P reserves of 47.8 MMBoe 2P reserves of 70.0 MMBoe Future growth potential from sub-salt prospects identified with advanced seismic *All reserve estimates as of 12/31/16 (1) Average daily production for FY 2016 3
Key Operating Characteristics of W&T Operating safely and effectively in the Gulf of Mexico for over 30 years Operate ~70% of our production Over 70% of our acreage is held by production 100% drilling success over last 3 years Track record for adding value to acquired assets through exploration and development History of acquiring producing assets with substantial upside including, Mahogany, Matterhorn, Virgo, Tahoe, and Neptune, to name a few Utilizing new seismic data to identify drilling opportunities Participating successfully in high value deepwater exploration projects Adding substantial reserves and production from deepwater projects like Big Bend, Dantzler, Neptune, Medusa & Virgo Continuing to screen and evaluate quality deepwater projects that potentially offer high rates of oil production Historically, W&T s EBITDA margin range is about 60% FY 2016 EBITDA margin of 45%, but improved in 4Q 2016 to 60% Working to reduce costs and focus on high margin projects 4
Strategy For Value Creation in a Lower Oil Price Environment Sustaining production while living within cash flow Production is expected to increase in 2017 with $125 million capital program Focusing on inventory of lower risk/higher return projects including, step-out exploration and development and lower cost workovers and recompletions Building on track-record for successful exploitation of acquisitions Leveraging expertise of technical teams, combined with innovations to add value to existing assets Better data is leading to better oil and gas recovery Focusing on improving returns Continuing to drive costs and expenses lower and optimize operations that has reduced LOE per BOE and D&C costs Surplus equipment and services in GOM allows for contract renegotiations and single source contracts with favorable terms Managing balance sheet Completed debt exchange to enhance financial flexibility and liquidity Raised $75 million in connection with exchange offer $243 million in liquidity as of January 2017 5
Steady Production on Lower Capital Expenditures Includes production associated with a 2017 capital budget of $125 million Combined with new projects, existing wells with incremental 2P and 3P reserves (that require no additional capex) can increase 2017 production over 2016 Cap Ex Production ($ MM) (MMBoe) $700 $600 $500 $400 $300 $200 $100 $0 2013 2014 2015 2016 2017E 20 18 16 14 12 10 8 6 4 2 0 6
Cost Reduction Efforts Continue $/Boe 25.00 Spending Reduction Program 20.00 $19.61 $19.94 15.00 $15.60 $13.81 10.00 5.00-2013 2014 2015 2016 General & Administrative Base Operating Expense Insurance Premiums Workover Expense Facilities Expense (1) (1) Reflects approximate amount of guidance mid-point 7
Extensive Organic Growth Opportunity Set Adding Value From Opportunities at Producing Fields Deep Inventory of organic growth opportunities 36 projects make up nearly $1 billion in drilling/capex inventory 90-165 MMBoe net unrisked exploration resource potential* Dominated by opportunities close to our Core Focus Areas Lower risk; faster online timing; increased ROR% Mahogany, EW910, MC243, Virgo, RIO Grande, Main Pass Area Leveraging our technological expertise Utilizing 3D & WAZ seismic and advanced processing to identify targets Exploiting our understanding of the GOM from 30+ years of operations and acquisitions Cost control and production optimization know how Investment focus Capital efficiency (NPV generation/$), payout timing, ROR %, HC type *Range based on P50 P10 success cases. 8
Gulf of Mexico A Prolific & Unique Basin The Permian Basin on Steroids, with Better Porosity and Permeability Highly prolific basin with multiple stacked pay Many of our fields have stacked pay Stacked reservoirs offer attractive primary production and recompletion opportunities Advanced seismic and geoscience greatly improve ability to identify drilling opportunities and enhances success Natural drive mechanisms generate incremental production from 2P and 3P reserves Typical fields with high quality sands have drive mechanisms superior to primary depletion alone Most fields enjoy incremental reserves adds annually Partly due to how reserve quantities are booked for SEC purposes Zone 1 Zone 2 Zone 3 Zone 4 Zone 5 Zone 6 Zone 7 Zone 8 9
Quality When it Matters The GOM has Superior Rocks Better Porosity and Permeability Allow for Better Flow and Production Rates GOM perms > 1 darcy. Permian perms in nano-darcies Generates higher cash flow velocity and delivers fast payback Generates better rates of return and return on capital Better decline curves than low perm onshore plays Recent GOM Type Well for W&T Actual Permian Well 10
Probable and Possible Reserves May Be Produced at No Cost Strong drive mechanisms allow production of reserves with fewer drilled wellbores 11
Incremental Cash Flow Associated with Probable and Possible Reserves (1) Probables and Possibles provide hidden value and significant upside Probable & Possible Reserves Add Value Economically $1.5 Billion PV-10 Total Incremental Value Increases with CAPEX $ in millions $1,600 $1,200 $800 $400 241 310 Possibles Probables 497 909 581 620 High potential upside compared to capex required $0 Cumulative CAPEX (3) (2) No CAPEX + Contingent CAPEX + CAPEX Required $0 $148 MM $255 MM (1) Figures reflect year-end 2016 NYMEX price case. (2) Probable and possible reserves with no direct CAPEX requirements that are largely associated with PNP and PUD reserves and therefore have associated future indirect CAPEX requirements. (3) Probable and possible cases that are largely associated with producing wellbores and require no additional future CAPEX requirements. 12
W&T Reserves Appreciation Actual Results SIGNIFICANT RESERVE GROWTH FROM INITIAL BOOKINGS 59.0 GROSS EUR RESERVES (MMBoe) Current 1P > Initial 1P booking 54.2 Current 1P > Initial 2P booking 34.5 33.2 31.8 Current 1P > Initial 3P booking 22.1 21.6 18.8 12.7 2.6 3.6 4.3 7.4 6.3 6.8 W&T Deepwater Field 1 (1) (2) (3) (4) 11.5 7.9 4.1 MAHOGANY T-2 Sand(4) All reserve estimates include cumulative production to date. 1P = Proved, 2P = Proved + Probable, 3P = Proved + Probable + Possible Current Proven Producing Reserve growth based on production to date. Initial 1P booking includes A-14 well only; Year 3 1P booking includes A-14 and A-18 wells W&T Deepwater Field 2 13
Acquisition Criteria A Proven Approach The Gulf of Mexico Offers a Large Opportunity Set Properties generating cash flow Strong current production rates Opportunity to reduce operating expenses Financeable Large portion of reserve base is proved developed and can be financed with commercial credit lines Solid probable/possible reserves attributable to incremental production (little to no cost) Identified upside Properties have undrilled prospects Workover or recomplete opportunities/effective wellbore utilization Contiguous acreage to existing heritage properties Facility upgrades/debottlenecking Secondary recovery projects Undeveloped lease blocks/acreage 14
History of Creating Long-Term Value from GOM Acquisitions Total USA $115 million Paid out in Aug. 2011 Current net production of 2,700 Boe/d from Matterhorn & Virgo Reserves at 12/31/16: 1P 8.9 MMBoe 2P 15.0 MMBoe 3P 23.0 MMBoe 2010 Newfield $206 million Paid out in Nov. 2014 78 offshore blocks, 65 of which are in deepwater. Reserves 1P 1.4 MMBoe at 12/31/16: 2P 2.4 MMBoe 3P 4.0 MMBoe 2012 Woodside $55 million Current net production of 1,500 Boe/d from Neptune & 24 additional deepwater blocks One exploration well brought on production in 2014. Exploration could double field size. Reserves 1P 1.4 MMBoe at 12/31/16: 2P 1.6 MMBoe 3P 2.0 MMBoe 2014 2010 2013 Shell Deepwater $116 million Paid out in Nov. 2012 Current net production of 3,375 Boe/d from Tahoe & 6 other fields. Reserves 1P 4.2 MMBoe at 12/31/16: 2P 5.7 MMBoe 3P 6.5 MMBoe Callon $84 million Current net production of 980 Boe/d from Medusa & 12 other fields Two exploration wells brought on production in June 2015. Reserves 1P 2.2 MMBoe at 12/31/16: 2P 3.5 MMBoe 3P 4.5 MMBoe 15
Operations and Opportunities
Key Near-Term Drilling Opportunities Low Risk / High Margin LEGEND Developed Leases Undeveloped Exploration Leases MP 243 Matterhorn Execute de-risked western waterflood Extension field drilling SS 349/359 Mahogany Field VIRGO Multiple P Sand drill targets Multiple T Sand drill targets Potential U Sand drill targets Mahogany Analogs in the GOM EW910 Field PUD drilling Low risk extension drilling Successful phase I Execute phase II (Multiple deep oil plays) Phase III: Drill PUDs from phase I and near-field exploration Selected Key Future Drilling Inventory and Core Investment Areas 17
2017 Capital Plan 2017 Budget: $125 million Estimated to increase production ~4% over 2016 volumes absent any acquisitions Projected six to eight wells to be drilled Balanced program of exploration and development Budget includes 20-25 recompletions totaling ~$26 million All drill and recomplete projects expected to generate high rates of return with relatively quick payback cycles Budget Criteria and Objective Increase production and revenues and add proved reserves Focus on projects that have a high probability of success, a high rate of return and a short term payout, which increase production levels year over year Drill within net cash flows and maintain liquidity Manage drilling inventory, should commodity prices improve Asset retirement obligation (ARO) of ~$78.3 million in 2017, declining significantly in the following year 18
Exploration Success at Ship Shoal 349 ( Mahogany ) Since 2011 SS Mahogany Continued Sub-Salt SS349 349 Mahogany Continued Sub-Salt Exploration & Development Success Exploration & Development Success Mahogany Wells Drilled Before and After Mid-2011 (WI: 100%, NRI: 83.3%) Substantially expanded the size and depth of the field since 2011 with drilling of eight wells Stacked pay sands: At least six pay zones proven to be productive in field Primary field pay has been the P Sand In 2013, A-14 well logged over 370 of net oil pay in five zones and discovered the T Sand Deep inventory of future drilling projects Currently P, Q and T Sand opportunities Future U Sand opportunities being matured following 2016 discovery Average production rate: Full Year 2016: ~4,900 Boe/d net (~75% oil) Full Year 2011: ~1,620 Boe/d net Additional Benefits: Proven success in the field Low risk projects Spread rig costs against more projects Low cost recompletion projects add production 19
Mahogany s Prolific P & T Sands Mahogany's primary field pay P Sand has cumulatively produced ~31 MMBoe since 1997 from multiple wells T Sand is 3,000 feet deeper and better quality than P Sand The A-18 success in 2016 solidifies the significant upside reserve potential for the T Sand Seismic and reservoir data may identify additional productive sands or expand potential size of T Sand SS 349 A-14 P Sand Log SS 349 A-14 T Sand Log P1 P2 P3 P4 20
SS 349 MAHOGANY Drilling Inventory Salt A-16 ST All productive sands are not shown Multi-target well: P, O, etc. P Attic Well Very low risk as the P/Q were penetrated by the A-18 drill; low cost as it s a ST drill; payout = ~1 year A-14 Original T Sand discovery well P Sand Crestal Inventory Maturing stacked P Sand and other zone opportunities A-18 Recent T Sand Successful Well Discovered new sand and found valuable attic play in P Sand. Commenced production Jan. 2017 Additional Benefits: Deep Inventory: multiple P Sand and T Sand opportunities Attractive Development Costs: F&D costs range from $5.50 per Boe to $13.50 per Boe Depths range from 15,500 to 20,000 Central P Sand PUD T Sand Low risk proved location updip from producing locations; near logged pay U Sand 21
EW910: Successful Phase I Campaign Building Inventory ST320 A2 & A3 wells EW 910 Expansion Deepwater platform Characterization: Producing field Important infrastructure hosts other production W&T assembled acreage position in last few years and built inventory. Low F&D costs; 100% rate of return; low risk exploration; stacked targets ST320 A-5 ST Discovery; Online IP Rate: 2,700 Boe/d PHASE I: Two wells completed one in 2015 and one in 2016; two discoveries + one PUD well set-up FIELD RATE: 4,544 Boe/d EW910 A-3 ST PHASE II & III: 2017+ (multiple drilling investment opportunities) Low cost drill (spread costs against more projects) Online fast (high rate of return) Recent success lowers risk on future drill Additional Locations Stacked Targets SubSea Development *W&T s working interest at EW 910 varies per well (range: 36% - 100%) Newly proved well; PUD and reserves; attic to A-5 EW954 A-8 Discovery; online IP Rate: Zone 1: 3,350 Boe/d Zone 2: 2,754 Boe/d 22
MC 243 Matterhorn Generating Value through Technology MATTERHORN WATERFLOOD MC243 A-2 10,000 Incremental reserves Daily Rate Oil (Bopd) Gas (Mcfpd) Oil Rate: Bopd 1,000 Recent success implementing Eastern Area A sand waterflood Increased reserves through enhanced technology and reservoir management Excellent pressure and rate response in East Area Peaked at > 1,200 Bopd Solid incremental reserves Development plan: exploit same reservoir in the West Area in 2018. 100 10 Gas Rate: Mcfpd 2014 Primary recovery only forecast 2015 2016 (WI: 100%, NRI: 100%) 23
Matterhorn Generating Shareholder Value through Advanced Technology and Optimization of Assets Eastern Waterflood Successful implementation of Enhanced Recovery Project Project: Waterflood high quality reservoir to improve sweep, increase and optimize recovery and to optimize reservoir management PHASE I Waterflood Future Successful Incremental Recovery Expansion Well Opportunity OOIP: 28 MMBO Total Recovery Factor: > 26% Reserves added: 2.0 2.9 MMBO New drill to expand into new target fault block; stacked pay potential A-5 ST2 Water Injector well Value Generation: $50 MM NPV Western Waterflood A-2 ST2BP2 Producer well Project: Duplicates the Eastern waterflood project on western flank OOIP: 34 MMBO Recovery Factor: projected @ > 32% Projected Incremental Reserves: ~ 3.7 MMBO De-risked following Eastern waterflood results PHASE II Waterflood Future Expansion Future Expansion Well Opportunity New drill to capture high side waterflood recovery Western Field Sector A-4 BP2 Western Sector Oil Producer Efficient capital project; well currently exists only requires conversion to injection Execution timing: set to follow A-7 depletion in a deeper, currently producing zone before conversion to the A sand for waterflood 24
VK823 VIRGO : Building the Inventory of Opportunities Benefits at Virgo De-risked drilling with 3D seismic, amplitudes and strong analog offsets Identified PUD drilling locations VIRGO Central Low risk extension (exploration) PROVED Updip of logged pay drilling Low risk Fast pay-back periods Established production facility Completed well on production quickly Platform rig drilling (lower cost & ease of access). VIRGO NORTH Stacked targets structurally high fault block Opportunities at Virgo Working Interest: 64% - 70% Average Payout = ~1 year Rate of Return = 100% Average Chance of Success = ~86% Average F&D cost = $11.70 VIRGO SW Known Pay PROVED Updip of logged pay Low risk 25
Potential Additional Drilling Opportunities LEGEND FAIRWAY Developed Leases Plant life extension 2 identified exploratory targets Undeveloped Exploration Leases SS 350/360 100% working interest Cost and operational synergies / leverage (extensional to SS349) MP 286 Impact oil drill target 3D supported Extensional to nearby production MP283 Rio Grande CYPRESS Miocene sidetrack Fast commercialization and early first oil through company owned infrastructure Neptune North flank drill targets (3) Extension drilling opportunities Opportunity to realize increased RF% due to reservoir quality Haleakala Impact oil ; deep miocene (sub salt) Selected Key Future Drilling Inventory and Core Investment Areas 26
Financial Overview
Recent Events Enhance Liquidity EW 910 A-5 first production Term loan financing Sale of Yellow Rose EW 910 A-8 first production Reinitiated drilling at Mahogany Mahogany A-18 completed ($376 MM) ($300 MM) 2Q 2015 3Q 2015 4Q 2015 Medusa first production 1Q 2016 2Q 2016 3Q 2016 4Q 2016 Closed exchange offer for Sr. Notes with 79% participation. Issued new PIK notes and common stock Big Bend & Dantzler first production (>50 MBoe/d gross) No long-term rig contracts 28
2017 Guidance ($ In millions) First Quarter 2017 Full Year 2017 2.0-2.3 8.3-9.2 Natural Gas (Bcf) 10.2-11.3 41.4-45.7 Total (Bcf) 22.5-24.9 91.1-100.6 3.7-4.1 15.2-16.8 First Quarter 2017 Full Year 2017 $46 - $51 $167 - $185 production taxes $5.6 - $6.2 $23 - $26 General and administrative $14 - $15 $57 - $63 Production Oil and NGL's (MMBbls) Total (MMBoe) Operating Expenses ($ in millions) Lease operating expenses Gathering, transportation & Income tax rate benefit -24% 29
EBITDA Comparison EBITDA Margins Historically Around 60% ($ in thousands) Year Ended December 31, 4Q16 Net Income (loss) Income tax expense (benefit) $ Net interest expense DD&A and accretion Ceiling test write-down EBITDA Adjustments: Derivative (gain) loss Debt issuance cost write-off & non op. costs Gain on exchange of debt Contingent assessment provision Loss on extinguishment of debt Contract option fee Litigation accrual Adjusted EBITDA Adjusted EBITDA Margin $ 2016 2015 16,483 1,017 11,508 38,883 67,891 $ (249,020) (43,376) 92,109 211,609 279,063 290,385 $ (1,044,718) (202,984) 97,205 394,071 987,238 230,812 65 1,622 37 7,672 4,983 (123,923) (7,672) 7,542 179,117 1,000 69,615 60% $ 45% $ 231,682 46% 2014 $ (11,661) (4,459) 78,194 511,102 573,176 2013 $ (9,283) - $ 563,893 60% $ 51,322 28,744 75,572 451,529 607,167 2012 $ 71,984 47,547 49,979 356,232 525,742 (119) - 6,289-128 (9,062) 598,114 10,250 542,281 61% $ 62% Annualized 4Q16 Adjusted EBITDA $278 million 30
Appendix
YE 2016 Reserves NYMEX vs. SEC Pricing YE 2016 - SEC Pricing Equiv Equiv PV-10 MMcfe MBoe $M YE 2016 - NYMEX Strip Pricing Equiv Equiv PV-10 MMcfe MBoe $M PDP PNP PUD PROVED 283,881 104,362 55,769 444,011 47,313 17,394 9,295 74,002 301,198 109,823 54,577 465,598 50,200 18,304 9,096 77,600 PROB TOTAL 2P 234,212 678,224 39,035 113,037 238,235 703,833 39,706 117,306 $ 449,407 228,918 76,608 $ 754,933 Reserve estimates are based on the following pricing: Year 2017+ SEC Pricing Oil Gas $ 39.25 $ 2.48 NYMEX Year 2017+ $ 2018+ 2019+ 2020+ 2021+ 2022+ 2023+ $ 735,549 338,696 138,016 $ 1,212,261 Reserve Replacement of 102% when comparing the 2016 NYMEX case to the 2015 SEC case. Delta Strip Pricing - SEC Pricing Equiv Equiv PV-10 MMcfe MBoe $M 17,317 5,461 (1,192) 21,587 2,886 910 (199) 3,598 4,022 25,609 670 4,268 $ 286,142 109,778 61,408 $ 457,328 NYMEX prices increase 2016 PV-10 by $457.3 MM over SEC prices. Strip Pricing Oil Gas 55.99 $ 3.62 56.59 3.14 56.10 2.87 56.05 2.88 56.21 2.90 56.51 2.93 56.77 3.12 32
2017 Financial Commodity Derivatives Quarter Average Floor Ceiling Feb-Mar '17 WTI Collars WTI Swaps 2,576 1,000 2Q17 WTI Collars WTI Swaps 4,000 1,000 50.00 55.25 60.15 55.25 3Q17 WTI Collars WTI Swaps 4,000 1,000 50.00 55.25 60.15 55.25 4Q17 WTI Collars WTI Swaps 4,000 1,000 50.00 55.25 60.15 55.25 Quarter (1) (2) Instrument Crude Oil Volume (Bbl/d) Instrument $ Natural Gas Volume (MMBtu/d) 50.00 55.25 $ 60.12 55.25 Average Floor Ceiling Feb-Mar '17 NG Collars 25,254 2Q17 NG Collars 30,000 3.07 3.96 3Q17 NG Collars 30,000 3.07 3.96 4Q17 NG Collars 30,000 3.07 3.96 This schedule only contains open hedge positions. Settled months are not included. All figures reflect weighted averages for the specified period $ 3.04 $ 3.97 33
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