September 5-7, 2017 Creating Value in the Gulf of Mexico - - PowerPoint PPT Presentation

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September 5-7, 2017 Creating Value in the Gulf of Mexico - - PowerPoint PPT Presentation

Barclays CEO Energy-Power Conference September 5-7, 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


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SLIDE 1

Creating Value in the Gulf of Mexico Barclays CEO Energy-Power Conference September 5-7, 2017

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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. 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

  • nly 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

  • ur 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.
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SLIDE 3

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Proved reserves:

1P 74.4 MMBoe 74.0 MMBoe 2P 113.6 MMBoe 113.0 MMBoe 3P 247.1 MMBoe 166.9 MMBoe

Oil & liquids % of proved reserves:

55% 56%

Gulf of Mexico Shelf

  • 480,000 gross acres (330,000 net acres)
  • 58% of daily production of 43,084 Boe/d(1)
  • 1P reserves of 48.1 MMBoe
  • 2P reserves of 70.6 MMBoe
  • Future growth potential from sub-salt projects identified with advanced seismic

Deepwater Gulf of Mexico

  • 250,000 gross acres (103,000 net acres)
  • 42% of daily production of 43,084 Boe/d(1)
  • 1P reserves of 26.3 MMBoe
  • 2P reserves of 43.0 MMBoe
  • Substantial upside with existing acreage

NYSE: WTI

(1) Average daily production for 2Q 2017

SEC Case as of: June 30, 2017 December 31, 2016

Premium Assets in the Gulf of Mexico

Premium GOM company with 30+ Years of Operating History

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SLIDE 4

Key Operating Characteristics of W&T

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  • Operate ~70% of our production
  • 80% of our acreage is held by production
  • 100% drilling success over last 4 years (14 exploration, 4

development)

Operating safely and effectively in the Gulf of Mexico for over 30 years

  • 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

Track record for adding value to acquired assets through exploration and development

  • 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

Participating successfully in high value deepwater exploration projects

  • 2Q 2017 Adjusted EBITDA margin of 59%, up from FY 2016

margin of 45%

  • Accomplished significant cost reductions with declining

commodity prices

Historically, W&T’s Adjusted EBITDA margin range is about 60%

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SLIDE 5

Strategy For Value Creation in a Lower Oil Price Environment

  • Production is expected to be flat 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

Sustaining production while living within cash flow

  • Leveraging expertise of technical teams, combined with

innovations to add value to existing assets

  • Better data is leading to better decisions and enhanced oil and

gas recoveries

Building on track-record for successful exploitation of acquisitions

  • Optimizing operations which has reduced LOE per BOE and D&C

costs

  • Continuing to drive costs and expenses lower
  • Surplus equipment and services in GOM allows for improved

contract terms and single source contracts with favorable terms

Focusing on improving returns

  • Completed debt exchange in 2016 and stock issuance to enhance

financial flexibility and liquidity

  • $240 million in liquidity as of August 2017

Managing balance sheet

5

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SLIDE 6

10 20 30 40 50 60 $0 $100 $200 $300 $400 $500 $600 $700 2013 2014 2015 2016 2017

6

Steady Production on Lower Capital Expenditures

Cap Ex Production

($ MM) (MBoe/d)

E

  • Includes production associated with a 2017 capital budget of $125 million
  • Existing wells, along with new projects, are expected to keep 2017 production flat
  • ver 2016
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SLIDE 7

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Cost Reduction Efforts Continue

(1) Reflects approximate amount of guidance mid-point (1)

$/Boe $/Boe

Spending Reduction

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SLIDE 8

Extensive Organic Growth Opportunity Set

Adding Value From Opportunities at Producing Fields

8

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 IRR%
  • Mahogany, EW910, Matterhorn, Virgo, Rio Grande, Main Pass Area …

Leveraging our technological expertise

  • Utilizing 3D & WAZ seismic and advanced processing to identify targets
  • Exploiting our insights of the GOM from 30+ years of operations and acquisitions
  • Cost control and production optimization know how

Investment focus

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

timing, highest IRR %

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SLIDE 9

Gulf of Mexico – A Prolific & Unique Basin

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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

  • pportunities 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 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 10

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

Recent GOM Type Well for W&T Actual Permian Well

 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

10

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SLIDE 11

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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 12

$- $400 $800 $1,200 $1,600 $2,000 $2,400 No CAPEX + Contingent CAPEX + CAPEX Required 299 436 464 251 431 1,702 Possibles Probables

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(1) Figures reflect mid-year 2017 SEC price case. (2) Probable and possible cases that are largely associated with producing wellbores and require no additional future CAPEX requirements. (3) 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.

In Increme mental l Value lue Inc Increases ses wit ith CA CAPE PEX

$2.2 Billion

PV-10

$0 $130 MM $317 MM

Cumulative CAPEX

Probables and Possibles provide hidden value and significant upside

(2) (3)

Incremental Cash Flow Associated with Probable and Possible Reserves (1)

Probable and Possible Reserves Add Economic Value

High potential upside compared to capex required

$ in millions

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SLIDE 13

20 40 60 80 100 120

Year 1 Year 5 Year 1 Year 4 Year 1 Year 4

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W&T Reserves Appreciation – Actual Results (1) (2)

GROSS EUR (MMBoe)

(1) 1P = Proved, 2P = Proved + Probable, 3P = Proved + Probable + Possible (2) Current proved producing reserve growth based on production to date. (3) 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 6.4 7.0 7.7 4.1 7.9 22.1 12.8 18.9

119.8

11.5 34.5 59.0 25.0 35.4 54.5 W&T Deepwater Field 1 MAHOGANY T-2 Sand(3) W&T Deepwater Field 2

Significant Reserve Growth from Initial NSAI Bookings

Current 1P > Initial 2P booking Current 1P > Initial 1P booking Current 1P > Initial 3P booking

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SLIDE 14

Acquisition Criteria – A Proven Approach

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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

The Gulf of Mexico provides a large acquisition opportunity set

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SLIDE 15

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History of Creating Long-Term Value from GOM Acquisitions

2010 2010 2013 2012 Callon $83 million

Investments post acquisition

Current net production of 800 Boe/d from Medusa & 12 other

  • fields. Two exploration wells

brought on production in June 2015 . Reserves 1P – 2.2 MMBoe at 6/30/17: 2P – 3.9 MMBoe 3P – 5.6 MMBoe

Newfield $206 million Paid out in Nov. 2014

78 offshore blocks, 65 of which are in deepwater. Reserves 1P – 1.2 MMBoe at 6/30/17: 2P – 2.0 MMBoe 3P – 3.7 MMBoe

Shell Deepwater $116 million Paid out in Nov. 2012

Current net production of 3,050 Boe/d from Tahoe & 6 other fields. Reserves 1P – 4.8 MMBoe at 6/30/17: 2P – 6.2 MMBoe 3P – 7.1 MMBoe

Total USA $115 million Paid out in Aug. 2011

Current net production of 3,600 Boe/d from Matterhorn & Virgo Reserves 1P – 8.4 MMBoe at 6/30/17: 2P – 13.6 MMBoe 3P – 23.8 MMBoe

2014 Woodside $55 million

Investments post acquisition Current net production of 1,350 Boe/d from Neptune & 24 additional deepwater blocks One exploration well brought on production in 2014 . Exploration could double field size. Reserves 1P – 1.5 MMBoe at 6/30/17: 2P – 1.8 MMBoe 3P – 2.3 MMBoe

(1) All Reserves based off mid-year 2017 SEC pricing.

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SLIDE 16

Operations and Opportunities

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SLIDE 17

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LEGEND

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

Key Near-Term Drilling Opportunities – Low Risk / High Margin

SS 349/359 “Mahogany Field”

  • Multiple ‘P’ Sand drill targets
  • Continued ‘T’ Sand extension

drilling

  • Potential ‘U’ Sand drill targets

and other field extension targets

EW910 Field

  • Successful Phase I in 2015-16
  • Execute Phase II (Multiple deep
  • il plays)
  • Phase III: Drill PUDs from phase I

and near-field exploration

“VIRGO”

  • PUD drilling
  • Low risk

extension drilling

SS 300

  • Undrilled fault block
  • Drill from platform
  • Low Risk
  • Stacked pay potential
  • Multiple wells in success case

MP 286

  • High impact oil prospect
  • Amplitude supported
  • Extensional to nearby

production MP 283

MC 243 “Matterhorn”

  • Execute de-risked

western waterflood

  • Extension field drilling

ST 224

  • New Exploration inventory
  • W&T Operate
  • Quality amplitude in strong

amplitude field trend.

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SLIDE 18

2017 Capital Plan

Budget Criteria and Objective 2017 Budget: $125 million

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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 cash flow and maintain liquidity

  • Manage drilling inventory, should commodity prices improve
  • Asset retirement obligation (ARO) of ~$83 million in 2017, declining significantly in 2018

Estimated to keep production flat with 2016 volumes absent any acquisitions Projected six to eight wells to be drilled

  • Balanced program of exploration and development
  • Budget includes around 25 recompletions totaling ~$30 million
  • All drill and recomplete projects expected to generate high rates of return with relatively

quick payback cycles

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SLIDE 19

2017 TIMELINE: Key Capital Projects

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2017 2018

A-18 A-8 S/T EW910 Area (ST311) SS 349 Area (Mahogany) SS 300 ST311 A2 (25,000’) A3 (22,500’) A10ST (A13 target area) A12 VIRGO A-16

WELL 2 (Cont.)

A-5 S/T Completed; on-line ST224 Well 1 TBD EP approved; APD filed Rig working for GOMEX ahead of W&T slot

MOB MOB

A2 ST or A7 ST (A14 target) Timing driven by rig/permits/barge time availability. Rig mobilization began in July

MOB

ST315

Field work

First Gas Pipeline re-route project; expected on line date: Sept. 2017 A-17 B5ST

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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 eight wells

  • 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.

  • Quality inventory of future drilling projects
  • Exploiting main pays in ‘P’ and ‘Q’ sands
  • Extending Reservoir limits with ‘T’ well(s)
  • Advancing ‘U’ Sand opportunities
  • Average production rate:
  • 2017: ~7,750 Boe/d net (~76% oil)
  • 2011: ~1,620 Boe/d net

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

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SLIDE 21

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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's primary field pay ‘P’ Sand has cumulatively produced ~33 MMBoe
  • ‘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 solidifies

the significant upside reserve potential for the ‘T’ Sand

  • 2017 program objectives include testing the reservoir limits of the ‘T’ sand further to substantiate the upside

seen with seismic and reservoir performance data.

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SLIDE 22

SS 349 “Mahogany” – 2017 Activities

Additional Benefits:  Strong 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’ Crestal Inventory

Maturing stacked ‘P’ Sand and

  • ther zone opportunities

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A-5ST ‘P’ Attic Well

Very low risk as the P/Q were penetrated by the A-18 drill; low cost sidetrack well; payout = ~1 year

A-18 Recent ‘T’ Sand Successful Well

Discovered new sand and found valuable “attic” play in ‘P’ Sand. Commenced production Jan. 2017 P Sand T Sand U Sand Salt

All productive sands are not shown

Discovery well A-14 Flowing ~1,345 Boepd A-18 Flowing ~4,700 Boepd A-16 Flowing ~1,275 Boepd A-17 (Drilling) T sand West Extension

Extend Reservoir limits to west

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SLIDE 23

Ewing Bank 910 - Successful Phase I Program with Phase II to Commence Soon

EW 910 Expansion

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

last few years and built inventory. PHASE I: Two wells completed – one in 2015 and one in 2016; two discoveries + one PUD well set-up FIELD RATE: 4,650 Boe/d PHASE II: 2017+ (multiple drilling investment opportunities)  W&T to drill (2) wells in Phase II  Low cost drill (spread costs against more projects)  Online fast (high rate of return)  Phase I success lowers Phase II risk PHASE III: 2018+ (open water wells)

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

Newly proved well; PUD and reserves; attic to A-5

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ST320 A-5 ST

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

Additional Locations

Stacked Targets SubSea Development *W&T’s working interest at EW 910 varies per well (range: 36% - 100%)

PHASE II PHASE III

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SLIDE 24

Mississippi Canyon 243 “Matterhorn” A-2 – Generating Value through Technology

MC243 A-2

Oil Rate: Bopd

MATTERHORN WATERFLOOD

  • Recent success implementing

Eastern Area “A” sand waterflood

  • Increased reserves through

enhanced technology and reservoir management

  • Excellent pressure and rate

response in East Area

  • A-2 well peaked at > 1,200 Bopd
  • Solid incremental reserves
  • Development plan: exploit same

reservoir in the West Area in 2018.

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Incremental reserves

Gas Rate: Mcfpd Primary recovery

  • nly forecast

Daily Rate

Oil (Bopd) Gas (Mcfpd)

10,000 1,000 100 10

2014 2015 2016

(WI: 100%, NRI: 100%)

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SLIDE 25

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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

  • OOIP: 28 MMBO
  • Total recovery factor: > 26%
  • Reserves added: 2.0 – 2.9 MMBO
  • Value generation: $50 MM NPV

Western Waterflood

  • 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
  • Efficient capital project - well currently exists,
  • nly 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

A-5 ST2 Water Injector well

PHASE II Waterflood Future Expansion

Western Field Sector A-4 BP2 Western Sector Oil Producer

PHASE I Waterflood

Successful Incremental Recovery A-2 ST2BP2

Producer well

Future Expansion Well Opportunity

New drill to capture high side waterflood recovery

Future

Expansion Well Opportunity

New drill to expand into new target fault block; stacked pay potential

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SLIDE 26

VK823 “VIRGO”: Building the Inventory of Opportunities

VIRGO Central

PROVED Updip of logged pay Low risk

VIRGO NORTH

Stacked targets structurally high fault block

VIRGO SW

PROVED Updip of logged pay Low risk

Known Pay

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Benefits at Virgo

 De-risked drilling with 3D seismic, amplitudes and strong analog offsets  Identified PUD drilling locations  Low risk extension (exploration) drilling  Fast pay-back periods  Established production facility  Completed well on production quickly  Platform rig drilling (lower cost & ease

  • f access).

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
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SLIDE 27

MP 286 Exploratory Well(1)

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  • W&T WI 100%/NRI 81.25%
  • Open water location in 300’ WD
  • >350 Acres untested Robust AVO in a

proven trend. Combination stratigraphic- structural trap

  • Quality Field analogs nearby
  • Modeling of Amplitude response

predicts thickness ~50’ pay

  • Nearby infrastructure operated by W&T

(Tie-Back to MP283 Host)

  • Reserves (unrisked)/Capital

‒ Gross P50: 4.3 MMBoe ‒ Net P50: 3.4 MMBoe ‒ Net DHC: $12.9 MM ‒ Net Capex P50: $30.9 MM

  • Financial Metrics (unrisked P50)(2)

‒ NPV: $68 MM ‒ IRR: 100% ‒ Payout: 2.1 years

(1) Slide corrected as of September 7, 2017. (2) Project Economics based on flat pricing of $50/bbl and $3/Mcf. Excludes abandonment costs.

Initial Exploration Well Location W&T Operated Virgo Platform W&T Operated MP283 Platform Host

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SLIDE 28

ST 224 – Low Risk Amplitude in Proven Amplitude Trend(1)

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Unrisked Gross Resource Potential P50 Bcfe P10 Bcfe Mean Bcfe Bul-1 Sand 41 93 51

  • W&T WI 39.0%/NRI 31.0175%
  • Open water location in 160’ WD
  • Proven producing amplitude trend with

many working analogs (low risk)

  • Stratigraphic trap against south fault
  • Good upside volume exposure
  • Currently securing rig
  • Reserves (unrisked)/Capital

‒ Gross P50: 41.1 Bcfe ‒ Net P50: 12.8 Bcfe ‒ Net DHC: $4.2 MM ‒ Net Capex P50: $13.3 MM

  • Financial Metrics (unrisked P50)(2)

‒ PV10: $19.4 MM ‒ IRR: 78.8% ‒ Payout: 2.32 years

Multiple Production Host Options Multiple Production Host Options Multiple Production Host Options Initial Exploration Well Location High Side Success Case Extension

(1) Slide corrected as of September 7, 2017. (2) Project Economics based on flat pricing of $50/bbl and $3/Mcf. Excludes abandonment costs.

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SLIDE 29

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LEGEND

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

Potential Additional Drilling Opportunities

FAIRWAY

  • Plant life extension
  • 2 identified exploratory targets

GC 19

  • Platform Drilling – Fast First Oil
  • Low Risk with quality analogs

Rio Grande

  • Extension drilling
  • pportunities
  • Opportunity to realize

increased recovery factor % due to reservoir quality

SS 350/360

  • 100% working interest
  • Cost and operational

synergies / leverage (extensional to SS349)

  • Impact Exploration

Drilling near “Mahogany”

“Neptune”

  • North flank drill

targets (3)

HI A384

  • 100% Working Interest
  • Long inventory of

prospects.

  • Maturing with new data

Exploration

  • Maturing Multiple drill
  • pportunities.
  • Fast commercialization

thru company owned infrastructure.

  • High impact rate.

“Medusa/Gladden”

  • Extension Drilling
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SLIDE 30

Financial Overview

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SLIDE 31

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P&A Performance – W&T Deepwater Well P&A’s

5 10 15 20 25 30

VK 1003 #2 MC755 SS2 GB 293 #2 GB 646 #1 GC82 #3 GC82 #4 BOEM Liability W&T AFE estimate Actual Cost Gross Exp. ($ million)

50% of BOEM cost 50% of BOEM cost 39% of BOEM cost 30% of BOEM cost 11% of BOEM cost 13% of BOEM cost

Helix Q4000 Ensco 8503

  • Overall program cost $35.2MM vs BOEM estimate of $101.1MM
  • Our costs were 65% below the BOEM estimated liability
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SLIDE 32

Long-Term Debt

($ in thousands)

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  • Exchange transaction resulted in debt reduction of over $400 million
  • Annual cash interest expense has been decreased by approximately $50 - $60 million

June 30, 2017 Principal Only Revolving Bank Credit Facility, due November 2018…………………………………

  • $

11.00% 1.5 Lien Term Loan, due November 2019…………………………………….. 75,000 9.00 % Second Lien Term Loan, due May 2020……………………………………… 300,000 9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020………………..…… 163,007 8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021…………………….…. 145,897 8.50% Unsecured Senior Notes, due June 2019……………………………………… 189,829 Long term debt, excluding carrying value adjustments……………………………873,733 $

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SLIDE 33

33

2017 Guidance

($ in millions)

Third Quarter Full Year Production 2017 2017 Oil and NGL's (MMBbls) 1.9 - 2.2 8.4 - 9.3 Natural Gas (Bcf) 8.2 - 9.0 36.1 - 40.0 Total (Bcf) 19.8 - 21.9 86.9 - 96.0 Total (MMBoe) 3.3 - 3.7 14.5 - 16.0 Operating Expenses Third Quarter Full Year ($ in millions) 2017 2017 Lease operating expenses $39 - $43 $149 - $165 Gathering, transportation & production taxes $6 - $7 $25 - $28 General and administrative $14 - $15 $56 - $62 Income tax rate benefit 32%

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SLIDE 34

34

EBITDA Comparison

($ in thousands)

2Q17 1Q17 2016 2015 2014 2013 2012 Net Income (loss)

33,315 $ 24,299 $ (249,020) $ (1,044,718) $ (11,661) $ 51,322 $ 71,984 $

Income tax expense (benefit)

(8,975) (7,588) (43,376) (202,984) (4,459) 28,744 47,547

Net interest expense

11,429 11,289 92,109 97,205 78,194 75,572 49,979

DD&A and accretion

40,364 39,990 211,609 394,071 511,102 451,529 356,232

Ceiling test write-down

  • 279,063

987,238

  • EBITDA

76,133 67,990 290,385 230,812 573,176 607,167 525,742

Adjustments: Derivative (gain) loss (2,194) (3,242) 7,672 (7,672)

(9,283) (119) 6,289

Debt issuance cost write-off & non op. costs 270 205 4,983 7,542

  • Gain on exchange of debt

(8,056) 245 (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)

  • Civil penalties

1,289

  • Litigation accrual
  • 10,250

Adjusted EBITDA

72,618 $ 65,198 $ 179,117 $ 231,682 $ 563,893 $ 598,114 $ 542,281 $

Adjusted EBITDA Margin

59% 52% 45% 46% 60% 61% 62% Year Ended December 31,

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SLIDE 35

Appendix

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SLIDE 36

36

Mid-Year 2017 vs. Year-End 2016 Reserves

SEC Pricing Reserve estimates are based on the following SEC pricing:

Equiv. Equiv. PV-10 Equiv. Equiv. PV-10 Equiv. Equiv. PV-10 MMcfe Mboe $M MMcfe Mboe $M MMcfe Mboe $M PDP 319,769 53,295 690,625 $ 283,881 47,313 449,407 $ 35,888 5,981 241,218 $ PNP 85,526 14,254 184,339 104,362 17,394 228,918 (18,836) (3,139) (44,579) PUD 41,378 6,896 79,761 55,769 9,295 76,608 (14,391) (2,399) 3,153 PROVED 446,673 74,445 954,725 $ 444,011 74,002 754,933 $ 2,661 444 199,793 $ PROB 235,036 39,173 234,212 39,035 824 137 TOTAL 2P 681,709 113,618 678,224 113,037 3,485 581 POSS 801,156 133,526 322,881 53,814 478,275 79,712 TOTAL 3P 1,482,865 247,144 1,001,105 166,851 481,760 80,293 MY 2017 - SEC Pricing YE 2016 - SEC Pricing Delta MY 2017 - YE 2016

Year Oil Gas 2017+ 48.95 $ 3.01 $ Year Oil Gas 2017+ 39.25 $ 2.48 $ MY 2017 - SEC Pricing YE 2016 - SEC Pricing

Proved PV-10 increased

  • ver 25% from YE 2016 to

MY 2017. 3P Reserves increased almost 150% from YE 2016 to MY 2017.

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SLIDE 37

37

2017 Financial Commodity Derivatives

(1) This schedule only contains open hedge positions. Settled months are not included. (2) All figures reflect weighted averages for the specified period

Floor Ceiling 3Q17 WTI Collars 4,000 50.00 60.15 WTI Swaps 1,000 55.25 55.25 4Q17 WTI Collars 4,000 50.00 60.15 WTI Swaps 1,000 55.25 55.25 Floor Ceiling 3Q17 NG Collars 30,000 3.07 3.96 4Q17 NG Collars 30,000 3.07 3.96 Quarter Instrument Volume (MMBtu/d) Quarter Instrument Volume (Bbl/d) Crude Oil Average Average Natural Gas

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SLIDE 38

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