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Presentation to Capital One Securities 13 th Annual Energy - - PowerPoint PPT Presentation

Presentation to Capital One Securities 13 th Annual Energy Conference December 5, 2018 Creating Value in the Gulf of Mexico Forward-Looking Statement Disclosure This presentation, contains forward-looking statements within the meaning of


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SLIDE 1

Creating Value in the Gulf of Mexico Presentation to Capital One Securities 13th Annual Energy Conference

December 5, 2018

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SLIDE 2

Forward-Looking Statement Disclosure

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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

  • r 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, many of which are described under “Risk factors” in our Annual Report on From 10-K for the year ended December 31, 2017 available on our website and at www.sec.gov. 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

  • perations; (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 Regarding Hydrocarbon Quantities. The U.S. 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, and on an optional basis, probable and possible reserves meeting SEC definitions and criteria. The company does not include probable and possible reserves in its SEC filings. This presentation includes information concerning probable and possible reserves quantities compliant with PRMS/SPE guidelines and related PV-10 values that may be different from quantities of such non-proved reserves that may be reported under SEC rules and

  • guidelines. In addition, this presentation includes Company estimates of resources and “EURs” or “economic ultimate recoveries”

that are not necessarily reserves because no specific development plan has been committed for such recoveries. Recovery of estimated probable and possible reserves, and estimates of resources and EUR’s and recoverable resources, are inherently more speculative than recovery of proved reserves.

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SLIDE 3

Gulf of Mexico Shelf

  • 440,000 gross acres (250,000 net acres)
  • 56% of daily production of 36,508 Boe/d
  • 1P reserves of 60.4 MMBoe / 2P reserves of 108.4 MMBoe(2)
  • Future growth potential from sub-salt projects identified with advanced seismic

Deepwater Gulf of Mexico

  • 210,000 gross acres (80,000 net acres)
  • 44% of daily production of 36,508 Boe/d
  • 1P reserves of 21.7 MMBoe / 2P reserves of 37.1 MMBoe (2)
  • Substantial upside with existing acreage

NYSE: WTI

Premium Assets in the Gulf of Mexico

Premium GOM company with 35+ Years of Operating History

3

Market Cap (2): $808 Million Enterprise Value (2): $1.5 Billion

(1) Mid-Year 2018 Reserve Report prepared by NSAI & DeGolyer and MacNaughton at SEC pricing (see slide 39). (2) Market Cap and Enterprise Value calculated using W&T’s stock price as of 11/30/18, $5.81/share and 10/18/18 cash balance of $40.8 million and total debt principal of $686 million. (3) EBITDA & Adjusted EBITDA are non-GAAP financial measures, see slide 38 for a reconciliation to GAAP net income.

Proved reserves:

Oil & liquids (% of 1P): 60%

  • Avg. Daily Production (3Q18):

36,508 Boe/d 9 mo. 2018 Adjusted EBITDA(3): $262.7 (60% EBITDA Margin)

Reserves PV-10% 82.1 MMBOE $1.4 Billion 145.5 MMBOE $2.4 Billion 265.3 MMBOE $4.1 Billion Current Reserve Report (2) 1P: 2P: 3P:

(1)

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SLIDE 4

High Quality Asset Base

4

W&T Key Assets

Note: The outer ring of the pie charts represent contribution by field, with color indicating field location on the map (1) Based on Mid-year 2018 NSAI and DeGolyer & MacNaughton Reserve Reports with SEC pricing (2) Pre-Tax PV10% excluding 1P asset retirement obligation (3) Breakout between Deepwater and Shelf reflects production from 10 largest fields as of respective time periods

74% 26% 56% 44%

2017 Avg. Daily Production(3) SEC 2P Reserves Mix(1)

39.9 MBoed 145.5 MMBoe

Shelf Deepwater All Other Fields By Water Depth By Field

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SLIDE 5

5

W&T Shares Outperformed Major Indices

3/12/2018 WTI Announces Drilling JV and Heidelberg Acquisition

14% 24% 12%

12/21/2017 WTI Announces Successful Exploration Wells 9/27/2018 WTI Launches Senior Notes Offering

Nov ‘18 Sept ‘18 July ‘18 May ‘18 Mar ‘18 Jan ‘17 Nov ‘17 May ‘17 July ‘17 Jan ‘18 Mar ‘17 Sept ‘17

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SLIDE 6

W&T’s Investment Highlights

  • Capital allocation to high return quick payback projects allowed W&T to

generate $294.9 million of operating cash flow in nine months of 2018

  • Q3 2018 Adjusted EBITDA(1) of $92.2 million and margin of 60%
  • Inventory of lower risk/higher return projects, plus upside opportunities

Generating Significant Free Cash Flow and High Profit Margins

  • Leveraging expertise of technical teams, combined with innovations to add

value to existing assets

  • Better seismic data is leading to better decisions and enhanced recoveries
  • Projects include high rate of return stacked-pay development with

exploration components in very large known reservoirs

High Quality Asset Base with Substantial Low-Risk Upside

  • Optimizing operations has reduced LOE per BOE and D&C costs
  • Platform drilling, subsea tiebacks to existing infrastructure and high quality

assets led to 2-year F&D costs < $8.00/BOE

  • Surplus equipment and services in GOM allows for improved contract terms

that significantly lowers drilling, development and asset retirement costs

Improving returns

  • In October 2018, closed debt refinance that reduced debt by $217 million,

increased borrowing facility by $100 million and extended maturities

  • Established a drilling joint venture that allows us to drill and exploit assets
  • n a promoted basis with reduced capital outlay
  • Leveraged low cost service environment to reduce P&A liabilities
  • Over $220 million in liquidity as of November 1, 2018

Restructured Balance Sheet and Good Liquidity

6

(1) EBITDA and Adjusted EBITDA are non-GAAP financial measures, see slide 38 for a reconciliation to GAAP net income.

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SLIDE 7

Gulf of Mexico – A Prolific & Unique Basin

7

Better Porosity and Permeability than the Permian Basin Highly prolific basin with multiple stacked pay development opportunities

  • Stacked reservoirs offer attractive primary

production and recompletion opportunities

  • Advanced seismic and geoscience greatly

improve ability to identify drilling

  • pportunities and enhance 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

  • These fields enjoy incremental reserve

adds annually, partly due to how reserve quantities are booked under SEC guidelines Zone 1 Zone 2 Zone 3 Zone 4 Zone 5 Zone 6 Zone 7 Zone 8

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SLIDE 8

Gulf of Mexico Investment Thesis

8 Permian GoM Eagle Ford Bakken Niobrara Anadarko (SCOOP / STACK) Other

Total: 10.4 MMBod

3.4 Gulf of Mexico Historical Oil Production

  • Aug. ‘18 US Oil Production by Key Region (MMBod)(1)

2nd Highest Producing Basin in U.S. Provides Unique Advantages Through Low Declining Production and Incremental Reserve Bookings

(1) Based on U.S. Energy Information Administration (EIA) data (2) Source: Bloomberg

~18% of Total

GOM production near all-time high WTI Midland Differentials(2) were ($12.25) as of 9/21/2018 compared to Q3 2018 WTI average differential of ($0.12)

GOM 500 1000 1500 2000 2500

MMBod

1.9 1.4 1.3 1.3 0.6 0.5

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SLIDE 9

W&T’s Strategic Capital Allocation Plan

9

Organic Projects Asset Acquisitions Inventory Expansion

Pursue compelling producing assets at attractive valuations with upside potential and optimization

  • pportunities.

Utilize GOM expertise and new technologies to identify and develop

  • projects. Evaluate

potential for joint venture funding. Focus on high rate of return projects and fields with multiple drilling opportunities that can generate cash flow quickly.

Maintain a prudent balance sheet and use free cash flow to grow

  • pportunistically

Generate Shareholder Value

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SLIDE 10

Key Corporate Highlights of WTI

10

  • W&T’s 3 year environmental record is 0.095, significantly outperforming the GOM

average of 10.2 BO/MMBO produced

  • Rigorous review of contractor safety performance and programs during selection
  • No employee fatalities since inception

Over 30 Years of Safe Operations in the Gulf of Mexico

  • Optimizing operations has reduced LOE per BOE resulting in Adjusted EBITDA

margins of ~60% in 9 mo. Of 2018 compared to ~60% for 2014 (pre-downturn)

  • Surplus equipment and services in the GOM allows for improved contract terms

and single source contracts with favorable terms has significantly lowered drilling & development costs Operational Cost Cutting Improving Cash Margins

  • Leveraging expertise of technical teams, combined with technological innovation to

unlock drilling upside

  • Better data has led to better decisions and robust oil and gas recoveries
  • ~93% success rate across 41 offshore wells drilled from 2011-YTD 2018

Rigorous Technical Evaluation Resulting in High Drilling Success

  • Strong drive mechanisms in the GOM allow production of reserves with fewer

drilled wellbores

  • Proven history of finding and exceeding estimated pre-drill reserves

Proven History of Realizing Probable and Possible Upside

  • WTI’s previous investment in offshore infrastructure provides for excess capacity

for low-cost sidetracks and tie-backs

  • As a result, WTI’s most recent 2-year rolling organic F&D costs are below $8/boe,

with visibility for F&D to remain around these levels over the mid-term Low Organic F&D Costs Driven by Existing Infrastructure

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SLIDE 11

Key Corporate Highlights of WTI (cont’d)

11

  • Marginal decreases in production through the down cycle despite a substantially

reduced capital program

  • Focused on inventory of lower risk/higher return projects with existing

infrastructure, including step-out exploration and development and lower cost workovers and recompletions Significant Full Cycle Cash Flow Generation

  • Monza JV accelerates drilling program and brings forward cash flow on a promoted

basis while diversifying exploration risk

  • Company continues to make accretive acquisitions with significant existing cash

flow and available drilling upside Long-Term Value Created by Innovative Farm-Outs Such as the Monza JV and Accretive Acquisitions

  • Leveraging existing infrastructure allows WTI to enhance the rate of return of near-

term drilling by bringing wells on production more quickly

  • Tiebacks to existing infrastructure creates cash flow through Production Handling

Agreements with third parties Infrastructure Advantage

  • Adding substantial reserves and production from deepwater projects like Big Bend,

Dantzler, Neptune, Medusa & Virgo

  • Continuing to screen and evaluate quality deepwater projects that offer high rates
  • f return

Successful Participation in Valuable Deepwater Exploration Projects

  • Prudent hurricane risk management through diverse production base, adequate

insurance coverage, and takeaway optionality – Hurricane Ike impacted 10 WTI structures (2 operated) – all were managed within insurance coverage and without pollution incidence

  • Average annual P&A liability estimate of ~$20.3 million over the next five years

Effective Hurricane Risk Management with Substantial Recovery and Proactive Management

  • f ARO
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SLIDE 12

Rigorous Technical Evaluation Resulting in High Drilling Success

12

Leads Screening Technical Evaluation AFE Review Execute

Process 2 1 3 4 5

Leads high graded for strategic agenda, and once approved, project team assigned and deadlines are set Cursory technical evaluation with management and land review with scoping cost and business and technical planning Full technical evaluation with probabilistic risk analysis, AFE costing and economic evaluation Presentation to Executive management for AFE approval Project turned over to execution team and deadlines set

1 2 3 4 5

Rigorous evaluation process has led to only one dry hole over the past four years and ~93% success rate since 2011

Over 400 leads evaluated since 2011 41 offshore wells drilled since 2011 (~93% success)(2)

Track Record of Drilling Success(1)

(1) 2013 and 2017 are each inclusive of 1 commercially successful well, drilled, but uncompleted during the respective periods (2) As of 9/25/2018

Success Rate 2011 2012 2013 2014 2015 2016 2017 YTD 18 2011-2018 YTD 100.0% 80.0% 85.7% 100.0% 100.0% 100.0% 83.3% 100.0% 92.7%

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SLIDE 13

13

Probable and Possible Reserves May Be Produced at No Cost

Strong drive mechanisms allow production of reserves with fewer drilled wellbores

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SLIDE 14

Proven History of Realizing Upside (Wells Drilled from 2013-2017(1))

14

Note: Based on Mid-year 2018 NSAI Reserve Report with SEC pricing (1) Includes all wells that were drilled during the 2013 – 2017 timeframe, except for MC 243 A5 – ST (this well was left out because it was a water injection well that was designed to add reserves at another well through waterflood and therefore not a typical D&C well), and MP 159 #1 and ST 224 #1 (dry holes)

Type of Well Drilled(1) Actual vs. Expected Well Results(1) 16 5 Exploration (Higher Risk) Development (Lower Risk)

Total Number of Wells Drilled: 21

  • Post-Drill 1P EUR was 114% higher than Pre-Drill P90/1P EUR estimates
  • Post-Drill 2P EUR was in line with Pre-Drill P50/2P EUR estimates
  • ~85% of the Wells Drilled Over 2013 - 1H 2018 exceed Pre-drill P90 Estimates(1)

48.4 147.2 54.8 103.6 146.7 0.0 20.0 40.0 60.0 80.0 100.0 120.0 140.0 160.0

Gross EUR (MMBoe)

Pre-Drill Management EUR Cumulative Production Post-Drill NSAI Mid-Year 2018 EUR P90/1P P50/2P

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SLIDE 15

$602 $426 $44 $1,072 $635 $322 $760 $1,717 Probables PV10%

15

(1) Figures reflect Mid-Year 2018 Reserve Report prepared by NSAI & DeGolyer and MacNaughton at SEC pricing of $57.67/BO and $2.92/MMBtu before differentials (see slide 39).

Proven History of Realizing Probable and Possible Upside (cont’d)(1)

  • WTI is focused on realizing the reserves upside and adding economic value across three

categories:

Prob + Poss Related to PDP Prob + Poss Related to PDNP + PUD Prob + Poss Unrelated to 1P Reserves

  • No additional capex required
  • Achievable because of WTI’s deep

understanding of the field

  • Some additional capex required
  • Lower-risk combination of behind

pipe recompletions and sidetracks

  • Additional capex required
  • Limited step-out risk

1 2 3

Probables and Possibles Upside (PV-10%)

Capex: $0 $242 $196 $439

1 2 3 Total

($ in millions)

$2,789

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SLIDE 16

10 20 30 40 50 60 70 80 90 100 Year 1 Year 6 Year 1 Year 5 Year 1 Year 5

16

W&T Reserves Outperform Forecast – Actual Results (1) (2) (3)

GROSS EUR (MMBoe)

(1) Figures reflect Mid-Year 2018 Reserve Report prepared by NSAI & DeGolyer and MacNaughton at SEC pricing of $57.67/BO and $2.92/MMBtu before differentials (see slide 39). (2) 1P = Proved, 2P = Proved + Probable, 3P = Proved + Probable + Possible. (3) Current proved producing reserve growth based on production to date. (4) Initial 1P booking includes A-14 well only; Year 4 1P booking includes A-14 and A-18 wells.

2.6 3.6 4.3 7.8 10.2 14.7 4.1 7.9 22.1 26.5 37.5 94.2 11.5 34.5 59.0 28.3 34.8 52.2 W&T Deepwater Field 1 MAHOGANY T-2 Sand(4) W&T Deepwater Field 2

Significant Reserve Growth from Initial NSAI Bookings

Current 1P > Initial 3P booking Current 1P > Initial 1P booking Current 1P > Initial 3P booking

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SLIDE 17

Leveraging GOM Acquisition Expertise & Relationships Gained Over Last 35 Years

17

Gulf of Mexico operators continue to divest attractive assets

Majors moving to ultra-deepwater and companies monetizing GOM assets to fund on-shore projects creates high-value asset acquisition opportunities Under capitalized independents with sizeable undeveloped reserves maybe ripe for consolidation with a proven GOM operator Companies exiting the GOM provides a large inventory of accretive asset acquisition opportunities

GOM Exits Asset Sales Consolidation Opportunities Bankruptcies

Distressed companies offer assets at highly attractive valuations thru bankruptcy proceedings

ACQUISTION OPPORTUNITIES

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SLIDE 18

Acquisition Criteria – A Proven Approach

18

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 / Waterflood
  • Undeveloped lease blocks / acreage

The Gulf of Mexico provides a large acquisition opportunity set

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SLIDE 19

19

History of Creating Long-Term Value from GOM Acquisitions(1)

(1) All Reserves based on mid-year 2018 SEC pricing. (2) Based on effective date of January 1, 2018

TOTAL

$115 million Paid out in Aug. 2011

Current net production of 2,320 Boe/d from Matterhorn and Virgo Reserves 1P – 7.9 MMBoe (6/30/18): 2P – 13.9 MMBoe 3P – 24.6 MMBoe

NEWFIELD

$206 million Paid out in Nov. 2014

78 offshore blocks, 65 of which are in deepwater Reserves 1P – 0.9 MMBoe (6/30/18): 2P – 2.3 MMBoe 3P – 4.6 MMBoe

WOODSIDE

$55 million

Investments Post Acquisition

Current net production of 1,000 Boe/d from Neptune and 24 additional offshore blocks One exploration well brought on production in

  • 2014. Exploration could double field size

Reserves 1P – 1.3 MMBoe (6/30/18): 2P – 1.7 MMBoe 3P – 2.1 MMBoe

CALLON

$83 million

Investments Post Acquisition

Current net production of 900 Boe/d from Medusa and 12 other fields Two exploration well brought on production in June 2015

Reserves 1P – 2.2 MMBoe (6/30/18): 2P – 4.0 MMBoe 3P – 6.8 MMBoe

COBALT

$31 million(2)

Current net production of 2,500 Boe/d from Green Canyon 859, 903, and 904 Reserves 1P – 0.7 MMBoe (6/30/18): 2P – 2.3 MMBoe 3P – 3.1 MMBoe

SHELL

$116 million Paid out in Nov. 2012

Current net production of 2,580 Boe/d from Tahoe and 6 other fields Reserves 1P – 3.6 MMBoe (6/30/18): 2P – 4.1 MMBoe 3P – 4.5 MMBoe

2010 2011 2012 2013 2014 2018 2017 2015 2016

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SLIDE 20

20

SS 349 Field (“Mahogany”) Case Study SS 349 Field (“Mahogany”)

  • WI: 100.0%, 360’ Water Depth
  • 1st commercially successful subsalt

development in the Gulf of Mexico (initial production in 1997)

  • Originally purchased Amoco’s interest in 2000
  • Purchased additional interest in 2004 & 2008
  • Cumulative purchase price of $175MM
  • Total Net Cash Flow (including capex) from

final purchase date (1) = $439MM

  • Have increased value by

Development and exploration drilling

Performing recompletes

Reworks and performance optimization

Current Reserves

  • 1P Reserves(2) :

29.6 MMBOE

  • 2P Reserves(2) :

49.6 MMBOE

  • 3P Reserves(2) :

115.4 MMBOE

(1) As of 6/30/18. (2) Mid-Year 2018 Reserve Report prepared by NSAI & DeGolyer and MacNaughton at SEC pricing of $57.67/BO and $2.92/MMBtu before differentials (see slide 39).

Mahogany Gross Production

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SLIDE 21

21

Total E&P Deepwater Acquisition Case Study “Matterhorn” & “Virgo” Fields

  • WI: 64% - 100%, 1,130’ - 2,400’ water depth
  • Purchased from Total E&P, USA in 2010
  • $115MM acquisition cost
  • Total Net Cash Flow (including capex) from

final purchase date (1) = $514MM

  • Have increased value by

Drilling sidetracks

Performing recompletes

Instituting waterflood

Entering processing arrangement ($58 million in processing revenues received to date)

Current Reserves

  • 1P Reserves(2) :

7.9 MMBOE

  • 2P Reserves(2) :

13.9 MMBOE

  • 3P Reserves(2) :

24.6 MMBOE

(1) As of 6/30/18. (2) Mid-Year 2018 Reserve Report prepared by NSAI & DeGolyer and MacNaughton at SEC pricing of $57.67/BO and $2.92/MMBtu before differentials (see slide 39).

Mahogany Gross Production Matterhorn A-2 Well (Gross)

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SLIDE 22

22

Shell E&P Deepwater Acquisition Case Study

VK 783 Field (“Tahoe”/“SE Tahoe”)

  • WI: 70% - 100%, 1,050’ Water Depth
  • Purchased Tahoe and SE Tahoe Fields along

with an ORRI in Droshky Field

  • Included subsea development and two fixed

platforms

  • $116MM acquisition cost
  • Total Net Cash Flow (including capex) from

final purchase date (1) = $317MM

  • Have increased value by

Upgrades to compression system

Low cost facilities upgrades

Current Reserves

  • 1P Reserves(2) :

3.6 MMBOE

  • 2P Reserves(2) :

4.1 MMBOE

  • 3P Reserves(2) :

4.5 MMBOE

(1) As of 6/30/18. (2) Mid-Year 2018 Reserve Report prepared by NSAI & DeGolyer and MacNaughton at SEC pricing of $57.67/BO and $2.92/MMBtu before differentials (see slide 39).

U U U

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SLIDE 23

23

W&T Deepwater Assets

’ 1,000’ 2,000’ 3,000’ 4,000’ 5,000’ 6,000’ 7,000’

Dantzler 6,555’ Big Bend 7,018’ Gladden 2,785’

  • P. Play

1,847’ Virgo 1,130’ Tahoe 1,001’ EW910 557’ Matterhorn 2,850’ Neptune 4,216’ Heidelberg 5,310’ Medusa 2,223’

  • W&T’s Deepwater portfolio is expanding and

diversifying. Our latest addition is the Heidelberg Asset (2018 acquisition).

  • We operate and participate in various Deepwater

Production Facilities, including TLPs, E-TLPs, SPARs, Deepwater fixed structures, and sub-sea fields.

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SLIDE 24

Exploiting Extensive Organic Growth Opportunity Set

24

  • ~50 projects with 82-170 MMBoe net unrisked exploration resource

potential of select near-term inventory that are nearby existing production and available infrastructure

  • Additionally, there are 25 projects with estimated 76-140 MMBoe net

unrisked exploration resource potential currently available to the Company

Deep Inventory of Organic Growth Opportunities

  • Lower risk; faster online timing; increased IRR%
  • Mahogany, EW910, Matterhorn, Virgo, Rio Grande, Main Pass Area …
  • Numerous opportunities on acreage that is held by production

Dominated by Opportunities Close to our Core Focus Areas

  • Utilizing 3D & WAZ seismic and advanced processing to identify targets
  • Exploiting our insights of the GOM from 35+ years of operations and

acquisitions

  • Cost control and production optimization know how

Leveraging our Technological Expertise

  • Capital efficiency (solid NPV generation per dollar invested), relatively short

payout timing, highest IRR %

  • Some near term inventory being drilled through the Monza joint venture,

accelerating cash flows to WTI

Investment Focus

Adding Value from Opportunities at Producing Fields

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SLIDE 25

25 Development Prospects Unrisked Estimated Metrics (2P-3P Range) Area EUR (MMboe) Capex ($MM) PV-10%($MM) Main Pass 1.9 - 5.2 $4 - $10 $40 - $74 Mississippi Canyon 4.8 - 7.3 49 - 61 105 - 180 Ship Shoal 33.5 - 101.0 130 - 249 490 - 1,722 Viosca Knoll 2.7 - 6.6 13 - 21 31 - 63 Other 1.3 - 3.2 18 - 24 25 - 69 Total 44.2 - 123.3 $215 - $365 $691 - $2,107 Exploration Prospects Unrisked Estimated Metrics (P50-P10 Range) Area Resource (MMboe) Capex ($MM) PV-10%($MM) Ewing Bank 11.4 - 15.3 $82 $185 - $265 Mississippi Canyon 5.9 - 7.9 48 130 - 184 Ship Shoal 7.7 93 125 Viosca Knoll 6.5 - 7.5 66 44 - 64 Other 6.3 - 8.1 60 - 64 82 - 127 Total 37.8 - 46.5 $348 - $353 $566 - $764

Select Near Term Inventory

~50 Identified Prospects with an Est. P10/3P Resource Potential of ~170 MMBoe Nearby existing production and available infrastructure

(1) Other includes Bay Marchand, East Cameron, Ewing Bank, and Garden Bank. (2) Other includes Atwater Valley, Eugene Island, High Island, and South Timbalier. (3) PV-10% estimates based on 6/29/18 NYMEX strip.

(1)

(2)

W&T Selected Growth Prospects 4 Development and 5 Exploration Prospects 2 Development Prospects 3 Development and 4 Exploration Prospects 5 Exploration Prospects 13 Development and 3 Exploration Prospects

(3) (3)

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SLIDE 26

GOM Drilling Joint Venture (Monza) with Private Investors

Accelerates Pace to Develop W&T’s High Return Inventory, Leverages Capital Dollars and Maintains Flexibility to Pay Down Debt and Make Acquisitions

26

  • The Company secured $361.4 million of equity for the development of 14 pre-identified

projects in the GOM with potential to upsize program over time with additional projects

  • Covers the total estimated cost of the 14 wells of $336 million, plus contingency
  • With five of the fourteen wells already underway and an increase in oil prices, the

investor group opted to close the fund in June 2018

  • W&T initially receives 30% of the net revenues from the drilling program wells for

contributing 20% of the capital expenditures plus associated leases and providing access to available infrastructure

  • Upon private investors achieving certain return thresholds, W&T’s share of well net

revenue increases to 38.4%

  • Allows W&T to develop its high return drilling inventory at a faster pace with a greatly

reduced capital outlay and maintain flexibility to make acquisitions and pay down debt

  • JV structure expands W&T’s access to well capitalized investors
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SLIDE 27

27

Monza Drilling JV - Strategic and Financial Benefits(1)(2)

  • The following analysis assumes that a historical W&T well is retroactively placed into the drilling JV program assuming

current strip prices

  • The adjusted pre-JV cash flows are based on the smaller capex amount contributed into the JV (20%)

100.0% 170% 5.6x 1.3 yrs 184.0% 366% 10.2x 1.1 yrs Cumulative Payback Cash Flow IRR MOIC Period 20.0% 20.0% 20.0% 20.0% 30.0% 38.4% Capex Initial Working Interest Contribution Working Interest at Investor JV Hurdle

(1) Run at NYMEX strip as of 8/24/2018 assuming common start date of 8/24/2018. (2) Projections based on company NSAI mid-year 2018 reserve report.

Wells in JV Partnership have Potential to Nearly Double Cash Flows Net to WTI for Net Capital Deployed and significantly enhance WTI’s economics

W&T gets an initial 10% promote, providing 20% of capital, but receiving 30% of cash flows After approximately ~15 months, the investor hurdle is cleared and W&T’s working interest climbs to ~38.4%

Benefits to W&T

Status Quo (No JV) Assuming Drilling JV

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SLIDE 28

28

LEGEND

Developed Leases Undeveloped Exploration Leases Selected Key Future Drilling Inventory and Core Investment Areas

Key Near Term/Recent Opportunities – Low Risk / High Margin

SS 349/359 “Mahogany Field”

  • 2018 Drilling:
  • Multiple ‘P’ Sand targets
  • Extension well/targets in

‘T/U/V’ Sands

  • A-17 successful well; On-line
  • A-5 ST successful well; On-line
  • A-19: Currently drilling; Deep well

EW910 Field

  • 2015-16: Phase I (2 new producers)
  • 2018: Execute Phase II: Spud Q2.

First well (A-2) successful and in completion mode.

  • 2019+: Phase III: Drill near-field

Open water and potential PUDs from Phase I

VK 823 “VIRGO”

  • Multi-well development

program

  • Low risk PUD and

extension drilling.

  • Well 1 (A-10 ST):

successful well; On-line.

  • Well 2 (A-12): successful

well; in completion mode.

Main Pass Area

  • Multiple recompletion
  • pportunities executed
  • r underway.

ST 315

  • Project completed Sept. ’17
  • On line at ~ 700 Boe/d

*Daily production rates presented are gross.

SS 300 B-5 ST

  • Successful discovery- TD Sept

2017

  • Dual completion
  • IP: ~1,100 Boe/d

All assets aside from Mahogany part

  • f Monza JV or eligible to be

included in Monza JV

slide-29
SLIDE 29

Legend:

2017 2018

EW 910 Field (ST 320) SS 349 Field (Mahogany) A-10ST (PUD) A-12 (North) VIRGO A-5 S/T Completed; on-line

MOB MOB

A-17 A-17 on line. A-5 ST on line. A-19 Drilled …. In Completion. Expect First Oil late Q4 2018.

Com

A-2 Drilled. A-2 in Completion. Expect First Oil late Q4 2018.

2019

W

Discovery First Production A-19 A-20 A-13 (Bobcat) TBD

Com

TBD

Com Com

ST320 A-2

Com

ST320 A-3

Com LL Drill

Gladden Deep Gladden Deep EW 953

LL Drill LL Tree

EW 953

Com

A-10 and A-12 on production; A-13 Drilling

LL Tree Com Com Com Com

DEEPWATER FLOATER PROGRAM

Offshore Facility 29 R M

Project Timeline: Key Capital Projects

slide-30
SLIDE 30

30

Successful Drilling Program at Ship Shoal 349 (“Mahogany”)

SS 349 “Mahogany” Continued Sub-Salt Exploration & Development Success

(WI: 100%, NRI: 83.3%)

  • Substantially expanded the size and depth of the field

since 2011 by drilling/sidetracking 13 new producing locations.

  • Stacked pay sands: At least six pay zones proven to

be productive in field

  • Historically, main pay has been the ‘P’ Sand
  • In 2013, A-14 well logged over 370’ of net oil pay in 5

zones & discovered the deep ‘T’ Sand.

  • In 2016, A-18 well logged oil pay beneath the ‘T’ sand in

the ‘U’ sand.

  • In 2018, A-17 well logged pay in the main field pays and

discovered pay in the deep ‘V’ sand. A-19 well logged pay in multiple sands including the ‘T” sand and currently

  • n flowback.
  • Quality inventory of future drilling projects
  • Exploiting reservoirs in ‘P’ , ‘Q’ & ‘T thru V’ sands
  • Extending Reservoir limits both in depth and aerially.
  • Field production rate (gross):
  • Current rate: ~12,000 Boe/d
  • 2011: ~1,290 Boe/d (Q3 2011)

Mahogany Field Map and Drilling History

SS 349 “Mahogany” Continued Sub-Salt Exploration & Development Success

Additional Benefits:  Proven success in the field  Low risk projects  Spread rig costs against more projects  Low cost recompletion projects add production

2017 Well Path Deviations

A8ST

A19

slide-31
SLIDE 31

31

SS 349 A-14 ‘T’ Sand Log SS 349 A-14 ‘P’ Sand Log

P1 P2 P3 P4

Mahogany’s Prolific ‘P’ & ‘T’ Sands

  • Mahogany Field has achieved cumulative production of 48.9 Million Boe
  • ‘T’ Sand is 3,000 feet deeper and better quality than ‘P’ Sand
  • The A-18 success in 2016 coupled with the performance and pressure history of both ‘T’ producers solidified

the significant upside reserve potential for the ‘T’ Sand

  • A-17 well success in 2017/2018 added material volumes in the field pay sands and the deeper ‘V’ Sand
  • In 2018, put the A-17 on line, drilled and completed the A-19, optimizing production through targeted

workovers, exploiting additional ‘P’ and ‘Q’ drilling locations, and additional extension drilling.

slide-32
SLIDE 32

SS 349 “Mahogany” – A-17 Western Field Extension Well

32

A-17 Well

Western Field Extension Success Western Reservoir Extension well; Success in (2) high quality

  • sands. Completed and

On-Line. P Sand T Sand U Sand Salt

All productive sands are not shown

A-17 WELL

  • Exploration/Extension well

tested and extended field limits vertically and western lateral field limits.

  • Well Status:
  • TD:

1/2/2018

  • Logged 2 high quality

sands 89’ MD pay (tight hole status).

  • Status:

Completed and On-line; Peak Rate > 1,800 Boe per day (V- sand only)

V Sand Main pays

slide-33
SLIDE 33

SS 359 A-5 ST: Q sand Completion

33

  • Development Well;

Completed in July 2018

  • Logged pay in ‘P’ and ‘Q’

Sands

  • Single Selective Completion

in ‘P’ and ‘Q’ Sands

  • ‘Q’ Sand to produce first
  • ‘Q’ Sand currently producing

approximately 2,000 Boe per day

3,000 2,700 1,800 1,500 2,100 2,400 900 600 300 1,200 Gas Oil Boe/d 7/13/18 9/30/18

Mahogany A-5 ST Well (Gross)

slide-34
SLIDE 34

SS 359 “Mahogany” A-19 Well

34

  • Drilled to total depth in 3Q 2018
  • Logged high quality net pay in

multiple sands

  • T sand to produce first
  • T sand up-dip from known oil
  • Currently on flowback

Our Third Producer from the T Sand

slide-35
SLIDE 35

35 Selected Key Future Drilling Inventory and Core Investment Areas

Partial List of Potential Additional Drilling Opportunities

LEGEND

Developed Leases Undeveloped Exploration Leases

W&T was awarded 9 leases (34,578 net acres) and high bidder on an additional 8 leases (38,028 net acres) in Gulf of Mexico Lease Sales in 2018

FAIRWAY

  • Plant life extension
  • 2 identified exploratory targets

Rio Grande

  • Extension drilling
  • pportunities
  • Opportunity to realize

increased recovery factor % due to reservoir quality

“Neptune”

  • North flank drill

targets

Exploration

  • Maturing multiple drill
  • pportunities
  • Fast commercialization

thru company owned infrastructure

  • High impact rate

Gladden Deep

  • Deep extension

Matterhorn

  • Extension drilling
  • Waterflood expansion

Medusa

  • Extension drilling

EW910 Area

  • Drilling Phase II

program currently

  • Phase III open

water locations near Infrastructure post 2019.

6 new leases awarded - Ship Shoal Area 2 new leases awarded – Eugene Island Area

HI A384

  • 100% working interest
  • Inventory of drill locations

and Production optimization

  • pportunities

High bidder

  • n 4 leases

– High Island Area

SS 349 (Mahogany Core Area)

100% working interest

  • Cost and operational synergies /

leverage (extensional to SS 349)

  • Impact exploration drilling near

“Mahogany” lease-hold positions

High bidder

  • n 2 leases

– Main Pass Area 1 new lease awarded – Viosca Knoll Area High bidder on 2 leases – South Timbalier Area

slide-36
SLIDE 36

Financial Overview

slide-37
SLIDE 37

37

2018 Guidance

($ in millions)

Estimated 2018 Capital Expenditures $95 Million

Fourth Quarter Full Year Production 2018 2018 Oil and NGL's (MMBbls) 1.9 - 2.1 7.9 - 8.1 Natural Gas (Bcf) 7.4 - 8.2 32.0 - 32.8 Total (Bcfe) 18.8 - 20.7 79.4 - 81.4 Total (MMBoe) 3.1 - 3.5 13.2 - 13.6 Operating Expenses Fourth Quarter Full Year ($ in millions) 2018 2018 Lease operating expenses $38 - $42 $143 - $158 Gathering, transportation & production taxes $6 - $7 $22 - $25 General and administrative $14 - $15 $57 -$63 Income tax rate benefit 0%

slide-38
SLIDE 38

38

EBITDA(1) Comparison

($ in thousands)

```

(1) EBITDA and Adjusted EBITDA are non-GAAP financial measures, see slide 44 for a reconciliation to GAAP net income.

9 Months Ended,

9/30/2018 2017 2016 2015 2014 2013 2012 Net Income (loss)

109,983 $ 79,682 $ (249,020) $ (1,044,718) $ (11,661) $ 51,322 $ 71,984 $

Income tax expense (benefit)

363 (12,569) (43,376) (202,984) (4,459) 28,744 47,547

Net interest expense

34,211 45,521 92,109 97,205 78,194 75,572 49,979

DD&A and accretion

114,807 155,682 211,609 394,071 511,102 451,529 356,232

Ceiling test write-down

  • 279,063

987,238

  • EBITDA

259,364 268,316 290,385 230,812 573,176 607,167 525,742

Adjustments: Derivative (gain) loss 2,840

  • 7,672

(7,672)

(9,283) (119) 6,289

Debt issuance cost write-off & non op. costs 654 888 4,983 7,542

  • Gain on exchange of debt
  • (7,811)

(123,923) Contingent assessment provision

  • 1,000
  • Loss on extinguishment of debt
  • 128
  • Contract option fee
  • (9,062)
  • Apache lawsuit
  • 6,285
  • EC 321 settlement
  • (1,109)
  • Contingent civil penalties/other

(194) 1,820

  • Litigation accrual
  • 10,250

Adjusted EBITDA

262,664 $ 268,389 $ 179,117 $ 231,682 $ 563,893 $ 598,114 $ 542,281 $

Adjusted EBITDA Margin

60% 55% 45% 46% 60% 61% 62% Year Ended December 31,

ADJUSTED EBITDA(1) MARGINS RETURNED TO HISTORIC LEVELS IN 2018

slide-39
SLIDE 39

39 34.5% 7.7% 13.7% 44.1% PDP PDNP PUD Probable 60.4% 39.6% Liquids Natural Gas 33.9% 8.4% 14.2% 43.6% PDP PDNP PUD Probable

Reserves Summary – Current Reserve Report (1)

(1) Mid-Year 2018 Reserve Report prepared by NSAI & DeGolyer and MacNaughton at SEC pricing of $57.67/BO and $2.92/MMBtu before differentials. (2) Pre-Tax PV-10% is a non-GAAP measure. (3) Pre-Tax PV-10% excluding 1P Asset Retirement Obligation.

145.5 MMBoe 145.5 MMBoe $2,242 MM

2P Reserves(1) 2P Reserves(1) 2P Pre-Tax PV10%(2)(3)

(2)

Current Reserve Report (SEC Pricing) Overview

(1) Reserve Category Total (Mmboe) % Liquids Pre-Tax PV-10% Proved Developed Producing (PDP) 49.3 55.3% $839.6 Proved Developed Non-Producing (PDNP) 12.2 63.6% 188.5 Proved Undeveloped (PUD) 20.7 66.9% 333.8 Total 1P Reserves (Excluding ARO) 82.1 59.4% $1,361.8 Total 2P Reserves (Excluding ARO) 145.5 60.4% $2,434.1 1P Asset Retirement Obligations (ARO) (192.3) Total 1P Reserves (Including 1P ARO) 82.1 59.4% $1,169.5 Total 2P Reserves (Including 1P ARO) 145.5 60.4% $2,241.7

slide-40
SLIDE 40

$60.0 $112.8 $81.5 $74.3 $32.6 $72.3 $72.4 $37.6 $22.5 $21.8 $13.7 $20.7 $27.6 $9.3 18% 19% 13% 12% 12% 60% 36%

0% 50% 100% 150% 200% – $50.0 $100.0 $150.0 $200.0 $250.0

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024+ PDP PNP PUD ARO as % of Capex

Proactive Management of Asset Retirement Obligations

40

Undiscounted P&A Schedule(1)(2)

…Resulting in Low ARO Burden Over Next 5 Years

Average annual ARO liability of ~$21MM

  • ver 2019-2023

(1) Net of amounts held in escrow (total of $16.1 million) (2) Additional P&A liability estimate of $213.8 million from 2024-2046, with an average annual burden of ~$9.3 million; $9.0 million of estimated total P&A liability after 2046 (3) ARO as a % of Capex represents ARO settlements for the term / ARO settlements for the term + E&P capex

(3)

Accelerating P&A To Capture Low Costs…

WTI took advantage of low service cost environments in 2015 and 2016 by bringing forward upcoming P&A liabilities ($ in millions)

Average

slide-41
SLIDE 41

Hedging Strategy Protects Cash Flow Without Limiting Upside

41

  • Over 75% of 4th quarter oil production is protected in a lower oil price scenario with an average floor

price of $60.05 and we have 10,000 bbls/day of oil production hedged in 2019 with an average floor

  • f $60.92
  • W&T’s equal-weighted swap and long-call positions lock in floor price, protecting future cash flows

and allowing opportunity to capture potential oil price increases through 1Q 2020

(1) Commodity Derivative positions as of 11/30/18

Average Volume Average Volume Bbl/day Strike Price Floor Ceiling MMBtu/day Floor Ceiling 4Q18 WTI Collars 2,000 $55.00 $72.75 4Q18 NYMEX Collars 50,000 $2.55 $3.76 WTI Collars 2,000 $60.00 $69.50 WTI Swaps 2,000 $63.80 $63.80 $63.80 WTI Swaps 3,370 $60.92 $60.92 $60.92 WTI Puts (long) 5,000 $60.00 $60.00 WTI Calls (long) 3,370 $61.00 1Q19 WTI Swaps 10,000 $60.92 $60.92 $60.92 1Q19 NYMEX Collars 50,000 $2.49 $3.98 WTI Calls (long) 10,000 $61.00 2Q19 WTI Swaps 10,000 $60.92 $60.92 $60.92 2Q19 NYMEX Collars 50,000 $2.49 $3.98 WTI Calls (long) 10,000 $61.00 3Q19 WTI Swaps 10,000 $60.92 $60.92 $60.92 WTI Calls (long) 10,000 $61.00 4Q19 WTI Swaps 10,000 $60.92 $60.92 $60.92 WTI Calls (long) 10,000 $61.00 1Q20 WTI Swaps 10,000 $60.92 $60.92 $60.92 WTI Calls (long) 10,000 $61.00 2Q20 WTI Swaps 6,703 $60.92 $60.92 $60.92 WTI Calls (long) 6,703 $61.00 Average Crude Oil Instrument Month/ Quarter Natural Gas Quarter Instrument Average

slide-42
SLIDE 42

Conclusion

42

Over 30 Years of Safe Operations in the Gulf of Mexico Operational Cost Cutting Improving Cash Margins Rigorous Technical Evaluation Resulting in High Drilling Success Proven History of Realizing Probable and Possible Upside Low Organic F&D Costs Driven by Existing Infrastructure

Creating Value in the Gulf of Mexico

slide-43
SLIDE 43

Additional Slides

slide-44
SLIDE 44

SS 300 B-5 ST – Successful Field Extension Well

  • New fault block field extension
  • well. Risked by prolific offset

production and seismic amplitudes

  • W&T

WI: 79% NRI: 62%

  • Drilled from W&T production

platform (SS300 B)

  • Prolific oil field in fault block

geometry traps. Extended field to an undrilled fault block with amplitudes to de-risk.

  • Successful well. Logged

~173’ pay in 5 sands. Completed well as dual producer.

  • Strong stable production since

first oil; Initial Rate: > 1,100 Boe/d; Current incremental rate ~ 1,000 Boe/d. Increased field

  • utput by > 170%
  • Field Extension into undrilled fault block
  • Prolific offset fault block (large with low risk)
  • High impact to field production rate

SS300 B-5 ST

  • Multiple stacked

pay sands.

  • Completed as dual
  • IP > 1,100 Boe/d

SALT

44

Productive Offset Fault Block

slide-45
SLIDE 45

VK823 “VIRGO”: 2018 Drilling Program

45

VIRGO A-10 ST (Well #1)

Successful well. > 300’ column. On-Line: Q2 ‘18

VIRGO A-13 (Well #3)

Offsetting Amp. to proved pay Program Add

VIRGO A-12 (Well #2)

Successful well; ROB-E pay; in completion mode. Expect new rate in Q3 ‘18

Additional Prospects & Locations

VIRGO Program

  • Multiple well drilling program off

Virgo deepwater platform

  • 5-8 locations
  • Mobilized Rig late ’17
  • Low risk: well control, 3D and

amplitudes Program

  • A-10 ST (Well #1)
  • Successful well; On-line Q2
  • IP > 1,200 Boe/d
  • A-12 (Well #2)
  • Acquired block in 2016
  • Successful well in Rob-E sand
  • Currently in Completion mode.
  • A-13
  • Next planned program well

(addition to initial program line-up)

  • Analog amplitudes; Stacked pays
  • Western Extension
  • Additional Prospects
  • Multiple additional locations.
  • All reachable from platform.
  • De-risked with amplitude analysis.
  • Some locations located in recently

acquired new lease-sale block.

Rates expressed as Gross well rates

slide-46
SLIDE 46

46

VIRGO VK822: A-10 ST Well

(Well #1 in 2018 drilling program)

J/L Sand Reservoir JL Stray

VIRGO A-10 ST

JL Upper: 113‘ Pay MD (76’ Pay TVD) 300’ Gross Hydrocarbon Interval MD

JL Upper JL Lower

  • WI: W&T Operator 15.96%(1); Water Depth: 1,130’
  • PUD well:

Updip from logged pay in A-4 well

  • Spud: 2/15/18

TD: 2/25/18 @ 16,770’

  • Logged > 300’ of Hydrocarbon column in target

zone JL sand

  • Additional pay zones in well
  • Initial Production Rate:

1,236 Boe/d gross

A-10ST

Downdip well control

(1) Due to Drill JV agreements, W&T’s effective working interest was reduced to 15.96%, with an effective NRI of 22.25%.

slide-47
SLIDE 47

47

VIRGO VK779: A-12

(Well #2 in 2018 drilling program) A-12

ROB E-5 RESERVOIR

VIRGO A-12

ROB E-5:

112.5‘ Pay MD (330’ MD column)

A-12 WELL

  • Drilled August 11, 2018.
  • 112’ MD pay in ROB E-5 reservoir; Offsets large

analogous producing reservoir.

  • Status: Completed and currently under flow

evaluation

ROB E-5 A-3 CUM: 28 BCF and 499 MBO

slide-48
SLIDE 48

Ewing Bank 910 - Phase II Drilling Program initiated in early 2018

EW 910 Expansion(1)(2)

  • Deepwater platform
  • Characterization:
  • Producing field
  • Important infrastructure – hosts
  • ther production
  • W&T assembled acreage position in

last few years and built inventory. PHASE I (2015-2016): Two discoveries and one future PUD location well set-up PHASE II (2018-2019):

  • Plan to drill (2) wells in Phase II
  • Platform Drilling
  • Low cost drill
  • Fast on-line timing
  • High ROR%
  • Status:
  • A-2 Well (First well) logged 163

feet of net pay, exceeding pre- drill estimates. Well completed and being prepared for flowback PHASE III (2019 +):

  • Open water exploration locations on

currently held leases. Host @ EW910.

ST320 A-2 & A-3 wells

Low F&D costs; 100% rate of return; low risk exploration; stacked targets

EW954 A-8

Discovery; online IP Rate: Zone 1: 3,350 Boe/d Zone 2: 2,754 Boe/d

EW910 A-3 ST

PUD and reserves; attic to A-5

48

ST320 A-5 ST

Discovery; Online IP Rate: 2,700 Boe/d

Additional Locations

Stacked Targets SubSea Development

(1) W&T’s working interest at EW 910 varies per well (range: 36% - 100%). (2) Daily rates presented as gross, unless otherwise noted.

PHASE II PHASE III

A3 A2

slide-49
SLIDE 49

Proven History of Realizing Probable and Possible Upside (cont’d)

49

(1) Excludes onshore reserves and production from 2011-2015 (2) 1H18 reserve life based on mid year 2018 NSAI and DeGolyer & MacNaughton reserve reports and 1H18 annualized production

WTI Has Consistently Maintained a ~5 Year Reserve Life For Nearly Two Decades(1) 2P

5.8 yrs 6.6 yrs 5.6 yrs 5.7 yrs 6.9 yrs 7.4 yrs 5.0 yrs 5.0 yrs 3.9 yrs 5.6 yrs 5.4 yrs 5.3 yrs 4.8 yrs 5.1 yrs 4.7 yrs 4.8 yrs 5.1 yrs 6.0 yrs

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 1H18

(2)

Average Reserve Life: 5.5 yrs

slide-50
SLIDE 50

Name Position Prior Companies Years of Experience Years With WTI

Founder, Chairman & CEO Mobil Taylor Energy 45 Years 35 Years EVP, CFO & CAO Allegheny Energy Raymond James Blackgold Capital 16 Years 10 Years SVP & CTO Exxon 33 Years 20 Years VP, General Counsel & Corporate Secretary BHP Billiton Jones Walker Schlumberger 25 Years 1 Year EVP, Drilling & Completions Anadarko Petroleum Kerr-McGee 29 Years 4 Years EVP, GOM Oryx Kerr-McGee 21 Years 12 Years VP, Geosciences Century Petroleum Anadarko Petroleum Exxon 40 Years 8 Years

Experienced Leadership Team

50

Tracy W. Krohn Tracy W. Krohn Janet Yang Janet Yang Steve Schroeder Steve Schroeder David Bump David Bump William Williford William Williford Jim Hersch Jim Hersch Shahid Ghauri Shahid Ghauri

slide-51
SLIDE 51

Nine Greenway Plaza, Suite 300 • Houston, TX 77046 Main line: 713-626-8525 Investor Relations: 713-297-8024 www.wtoffshore.com • investorrelations@wtoffshore.com