Johnson Rice Energy Conference New Orleans October 2 nd , 2013 - - PowerPoint PPT Presentation

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Johnson Rice Energy Conference New Orleans October 2 nd , 2013 - - PowerPoint PPT Presentation

Johnson Rice Energy Conference New Orleans October 2 nd , 2013 Overview - W&T OFFSHORE (NYSE: WTI) Six Months Ended Operating Locations ($ in millions) June 30, 2013 Revenues $494.6 Adjusted EBITDA $311.1 Permian Basin Proved


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Johnson Rice Energy Conference

New Orleans – October 2nd, 2013

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SLIDE 2

Revenues $494.6 Adjusted EBITDA $311.1 Proved Reserves (PV-10)

(As of December 31, 2012)

$2,820.0 Dividend Yield

(2012)

6.9% Capital Spending

(excludes acquisitions)

$299.2 Average Daily Production July August Oil (MBbls/d) 18.6 18.6 NGLs (Mgal/d) 197.6 219.6 Natural Gas (MMcf/d) 120.3 132.6 Total (Mboe/d) 43.3 45.9

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Overview - W&T OFFSHORE (NYSE: WTI)

Six Months Ended June 30, 2013

Operating Locations

Permian Basin East Texas Gulf of Mexico As of December 31, 2012 Reserves by Category MMBoe Bcfe Proved 117.5 705.1 Probable 38.4 230.3 Possible 82.4 494.4

Current Avg Daily Prod. (Mboe/d) 47.5

($ in millions)

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SLIDE 3

2

Revised 2013 Capital Expenditures Budget

  • Budget changes still align with the 2013 focus of organic growth

– Additional drilling activity in the deepwater with a second exploration well – Completion costs from our earlier successful drilling activity – Additional onshore drilling at our Yellow Rose field – Leasehold and seismic costs to support growth

45% 21% 14% 20%

2013 Revised CAPEX Budget of $550 million

Offshore Exploration Offshore Development Onshore Exploration Onshore Development

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3

Current Activity for W&T Offshore

  • Currently participating in the drilling of the “Dantzler” deepwater prospect at

MC 738/782 operated by Noble Energy

  • Spud the Ship Shoal 349 “Mahogany” A-15 deep shelf, sub-salt exploratory

well

  • Brought on production the Ship Shoal 349 A-4 recompletion
  • Mobilizing rig to our EC 321 field to drill the A-2 exploration well
  • Mobilizing unit to complete the MC 243 A-5 well
  • Expect sanction of Rio Grande complex to accommodate exploratory

deepwater discoveries

  • Multiple offshore wells coming online during 2H 2013
  • Currently drilling our first Wolfcamp “B” horizontal well at our Yellow Rose field
  • Fifth horizontal in East Texas planned for fourth quarter of 2013
  • Acquisition market still showing numerous opportunities
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SLIDE 5

4

Reserves Growth with a Focus on Oil

0.0 20.0 40.0 60.0 80.0 100.0 120.0 2009 2010 2011 2012

Proved Reserves

(MMBoe)

Crude Oil Proved Developed Total Proved Reserves

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Continued Oil and Total Production Growth

2 4 6 8 10 12 14 16 18 2010 2011 2012 2013E* Total Production Oil Production

MBoe

* 2013 figures represent the mid-point of full year guidance

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Growth Opportunities in 3P Reserves

Significant growth potential from our 3P reserves

  • Gross resource potential extends well beyond our 3P reserves

PDP 62.6 PDNP 24.3 PUD 30.6

Total Company Resources (in MMBoe)

Possible 82.4 Probable 38.4 Proved 117.5

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7

Multiple Avenues to Achieve Organic Growth

─ Permian & East Texas

  • ~220,000 gross acres

─ Proved Reserves(1)

  • 31.6 MMBoe

─ Est. Daily Sales Volumes(2)

  • 4,065 Boepd net

GOM DEEPWATER ONSHORE TEXAS GULF OF MEXICO SHELF

─ Deepwater (over 500’)

  • ~480,000 gross acres

─ Proved Reserves(1)

  • 27.0 MMBoe

─ Est. Daily Sales Volumes(2)

  • 15,301 Boepd net

─ GOM Shelf (under 500’)

  • ~710,000 gross acres

─ Proved Reserves(1)

  • 58.9 MMBoe

─ Est. Daily Sales Volumes(2)

  • 26,785 Boepd net

(1) Proved reserve figures are as of year end 2012 (2) Daily sales volumes are estimates based upon preliminary August 2013 sales volumes

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SLIDE 9

8

Balance – The Offshore Component

W&T has continued to grow its footprint in the Gulf of Mexico through acquisitions and leases sales

  • 65 lease blocks

acquired from Newfield (59 exploratory blocks)

  • 13 new OCS leases via

recent lease sales

  • Acquired interest in

MC698 “Big Bend”, MC699 “Troubadour”, and MC 738/782 “Dantzler”

  • Offshore properties still

account for ~ 90% of W&T’s production

Leases acquired over past two years W&T Legacy properties

W&T has ~1.2 million gross acres under lease in the GOM

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SLIDE 10

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Exploration and Development - GOM

WC 73 #2

Development Awaiting flow line hook-up Q4 2013 – 1st production

HI 21

Development Successful well, Completion operations

SS 349 “Mahogany”

Exploration A-14 Well: T-Sand producing A-15 Well: Well spud, delayed

MC 243 “Matterhorn”

Development & Reservoir Support A-2 ST: On production A-5: successful well, completion operations mobilizing

MC 738/782 “Dantzler”

Exploration Currently drilling

MP 108

Exploration B-1 ST: Producing

EC 321 A-2 ST

Exploration Mobilizing rig

MC 698 & 699 “Rio Grande” complex

Exploration Discoveries

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Deepwater Exploration – MC 738/782, “Dantzler”

MC 738/782 “Dantzler”

(WI: 20%, NRI: 16.25%)

  • Summary – Deepwater prospect with

reservoir in Lower Miocene against

  • salt. Nearby offset well has oil shows

and 1,200’ of significant sand in the target section.

  • Well currently drilling in 6,574’ of

water to a target depth of 19,150’

  • Results are expected by year-end

MC 698 “Big Bend” 2012 discovery

MC 738/782 “Dantzler"

W&T WI: 20% Total Gross Resource* 50 - 220 MMBoe (P75 - P25)

*All figures are operator (NBL) estimates

Dantzler

MC 698 & MC 699 “Rio Grande” complex

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Deepwater Discoveries – “Rio Grande” Complex

MC 698 “Big Bend” and MC 699 “Troubadour”

(WI: 20%, NRI: 16.7%)

  • Summary – Deepwater exploration wells in

adjacent lease blocks. Big Bend was a 2012 oil discovery and Troubadour is a 2013 gas discovery drilled in 7,273’ of water to a total depth of 19,510’. The two properties make up the “Rio Grande”

  • complex. Development planning is

progressing and sanction is expected by year end. First production is expected in late 2015. MC 698 “Big Bend” 2012 discovery MC 699 “Troubadour” 2013 discovery

MC 698 "Big Bend" and MC 699 “Troubadour” Rio Grande complex W&T WI: 20% (both wells) Total Gross Resource* 50 - 100 MMBoe (P75 - P25)

  • Est. Oil Volumes*

75%

*All figures are operator (NBL) estimates

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SS 349 “Mahogany”

Continued Sub-Salt Exploration & Development Success

(WI: 100%, NRI: 83.3%)

  • Mahogany production ~ 75% oil
  • Multi-horizon production

‒ Primary Field Pay is P-Sand ‒ Multiple producing horizons recently discovered

  • Production platform sits in ~375

feet of water on GOM shelf

  • Field reached new peak

production rate including the new T-Sand in late July:

‒ 9,827 Boepd net (11,792 gross)

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Exploration – GOM Shelf

SS 349 A-4 Recomplete Producing SS 349 A-14 Deep T-Sand target Exploration Discovery in T-sand Producing SS 349 A-15 Multi-Sand Target Exploration 5 stacked target horizons

2013 Activity at SS 349

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SS 349 “Mahogany” A-14 Well

Deep Shelf, Sub-Salt Discovery

(WI: 100%, NRI: 83.3%)

  • Summary – Exploratory well which

discovered new reserves in the T-sand and logged significant additional pay in four additional hydrocarbon bearing zones

  • Status – producing from T-Sand
  • T-Sand peak production rate

‒ 3,870 Boepd net after royalties

(4,644 gross Boepd, 77% crude oil)

  • Pre-drill unrisked potential

‒ 3.1 MMBoe (T-sand only, P-sand is

additional ~3.0 MMBoe)

Future development opportunities were identified in the M, N, O, and P- sands which create additional upside beyond the discovery of the T-sand

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Exploration – GOM Shelf

The A-14 exploration discovery provides significant reserve and production additions, and provides future exploration targets throughout this expanding field. SS 349 A-14 results:

  • Logged ~370’ of total pay
  • Encountered 5 pay sands
  • Reserve additions &

immediate production P-Sand logged over 123’ of measured depth pay, more than anticipated T-Sand discovery is the deepest producing horizon in the field M, N, & O-sands found pay – resulting in reserve additions with development opportunities

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SS 349 “Mahogany” A-15 Well

Deep Shelf, Sub-Salt Exploration

(WI: 100%, NRI: 83.3%)

  • Summary – Single well bore targeting

five separate sands (N,O,P,Q,Q5)

  • Initial Est. Cost - $34.5 million
  • Well spud in September, but is delayed

approximately one month for the A-12 well workover

  • Target well depth from 13,000’ to

15,500’

  • Target IP – 1,390 Boepd
  • Est. 1st production – Q1 2014
  • The A-15 targets some of the same

horizons that logged pay in the A-14 well (N, O, and P-sands)

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Exploration – GOM Shelf

A-15 Project NPV: $35 - $120 million

The A-15 well will represent the 7th consecutive well at “Mahogany” as part of a two year continuous drilling program.

Target reserve potential: 1.8 – 6.2 MMBoe SS 349 “Mahogany”

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Exploration – GOM Shelf

EC 321 A-2 ST

(WI: 100%, NRI: 83.3%)

  • Summary – Targeting new

reserves in the Lentic 1 sand by drilling a side-track from the existing A-2 well bore

  • Initial Est. Cost - $13.6 million
  • Target well depth – ~8,500’ TVD
  • Target spud date – October 2013
  • Target IP – 850 Boepd
  • Unrisked potential – 1.1 MMBoe
  • Project NPV ~ $35 MM

East Cameron 321 field is situated 97 miles off the coast

  • f Louisiana in 225’ of water. Cumulative production

through December of 2012 was 93.6 MMBoe. EC 321 A & B production platforms W&T Offshore lease blocks

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Development – Deepwater GOM

MC 243 “Matterhorn”

(WI: 100%, NRI: 100%*)

A-5 Well: The well logged ~220’ of

measured pay (one of the thickest “A” sand intervals in the field). The A-5 will now be produced for a period of time.

  • Est. completion: mid-Q4 2013
  • Upside Case – Positive results from the

A-5 well will de-risk and provide momentum for future field development projects.

*This lease provides for royalty suspension for the first 87.5 MM barrels. Cumulative production is <20 MM barrels.

Matterhorn TLP MC 243 A-2 well Producing MC 243 A-5 Successful well

Completion operations

NPV ~ $50 MM

West Sector

Upside target for follow

  • n de-risked project

NPV ~ $50 -$150 MM

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MP 108 B-1

(WI: 100%, NRI 82%)

  • Summary – Exploration well

recently completed. The well discovered reserves in both the Tex W-6 (73’ measured depth pay) and Tex W-3 (30’ measured depth pay), both of which will result in net reserve additions.

  • Est. Prod. ~ 950 Boepd net

(80% gas, 10% oil, 10% NGLs)

  • Target well depth – ~14,000’ TVD
  • Unrisked potential – 1.8 MMBoe
  • Evaluating additional opportunities

in the field and may drill another well in 2014

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Exploration – GOM Shelf

B B3 E Platform A Platform

MP 108 B-1

Successful well, producing

B Platform D Platform

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18

Development – GOM Shelf

High Island 21 (WI: 100%, NRI: 81%)

  • Summary – Gas and liquids development

targeting the LH 20 sands

  • Result – The well logged pay in targeted LH-

20 sand plus additional upside pay in LH-16 exceeding original expectations

  • Target well depth ~12,500’
  • Target IP – 1,500 Boepd
  • Est. 1st production – Q3 2013

West Cameron 73 #2 (WI: 30%, NRI: 24%)

  • Summary – Gas and liquids development

well drilled in 2012 which logged over 150 feet of pay across multiple zones

  • Status – Awaiting flow line hook-up by
  • perator (projected early Q4)
  • Est. 1st production – Q4 2013

WC 73 #2

Production expected Q4 2013

HI 21 A-1

Completion phase

HI 21: water depth of 36 ft. WC 73: water depth of 33 ft.

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– Year to Date Results:

  • Drilled five successful wells to date,

including a significant discovery at our SS 349 “Mahogany” field in the T- Sand, with three additional upside pay zones encountered

  • Identified multiple potential future

drilling locations in our premier

  • ffshore sub-salt oil field, SS 349

“Mahogany”

  • Increasing oil production, resulted in

raising full year guidance for oil and NGLs

  • Drilled our second deepwater

exploratory well in two years

Offshore Projects – Solid Results, More to Come

– Current and Upcoming Projects:

  • Drilling the “Dantzler” deepwater prospect
  • New exploratory wells, SS 349 A-15 and

EC 321 A-2 ST, both seeking new oil reserves

  • Production anticipated from MC 243 A-5,

HI 21 A-1, and WC 73 #2 wells this year

  • Discovery at MC 699 “Troubadour”
  • Anticipate sanctioning of Rio Grande

development (MC 698 & MC 699) project before year end

  • New seismic data received for multiple
  • ffshore fields
  • Evaluating new targets for future wells at

SS 349 “Mahogany” field

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Balance – The Onshore Component

  • Predictable onshore reserve growth over time
  • Multiple upside opportunities through down-spacing and horizontal benches (significant potential)
  • Continuous growth of long-life steady oil production

2,000 2,500 3,000 3,500 4,000 4,500 5,000 mid year 2012 year end 2012 mid-year 2013 August 25, 2013 Bbls

Production and Sales Growth at Yellow Rose

Gross Oil Production Net Sales in Boepd

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Yellow Rose (WI: 100%, NRI: ~78%)

  • Summary: Permian basin exploration and development

project with long-life reserves

  • 2013 budgeted drilling activity: 7 horizontal and 20

vertical wells. Currently running two rigs.

  • W&T recently increased its acreage position by ~10% at

its Yellow Rose prospect. Total net acreage: 25,730.

  • Peak production rate: ~4,442 Boepd net (5,507 gross)

Key Points for Yellow Rose

  • 40 acres down-spacing (verticals) tested positive during
  • 2012. Potential 20 acre spacing test in 2014.
  • Initial horizontals (6) targeted Wolfcamp “A”
  • First horizontal Wolfcamp “B” well currently drilling and

results are expected before year end

  • Yellow Rose acreage is more than 80% “held by

production”

  • Acquired 3D seismic covering most of our acreage

position and have utilized micro-seismic to enhance

  • verall field planning

Exploration and Development - Onshore

Yellow Rose avg. July production mix

  • 77% crude oil, 14% NGLs, 9% gas

Yellow Rose encompasses 25,730 net acres covering portions of Gaines, Dawson, Andrews, and Martin counties

Gaines Dawson Martin Andrews

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– Vertical Growth Opportunities:

  • Majority of reserves booked at 2012 YE were
  • n 80 acre spacing (~267 locations)

– Some 80 acre locations associated with new acreage still are unbooked

  • Potentially ~260 unbooked 40 acre locations
  • Potentially ~600 unbooked 20 acre locations
  • Could provide for ~860 drilling locations with a

target net EUR of 100 Mboe per well(1) – Up to 86 million barrels of unbooked reserves on verticals alone(2)

  • Onshore wells are targeting IRRs between

17% - 25%, which should have upside if economies of scale are at play in a larger development

Permian Basin Upside Potential – Vertical Wells

Continued improvement in the vertical results points towards the potential for better overall field economics as down- spacing occurs and more wells are completed.

~4,000 feet of correlative interval

Vertical wells are being completed in 10 to 12 different zones

(1) Net EUR of 100 Mboe is a target figure reflecting oil and unprocessed gas production (2) Potential reserve figure assumes 100% viability for 20 acre downspacing across the Yellow Rose field
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20 40 60 80 100 120

Q2 2012 Q3 2012 Q2 2013 Q3 2013

Yellow Rose 30 Day Average IP rate (Boepd gross)

30 Day Average IP rate (Boepd gross) 23

Continued Improvement in Vertical Wells

Boepd rates above reflect gross production in barrels of oil and unprocessed well-head gas. Boepd

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– Horizontal Growth Opportunities:

  • Thus far, W&T has only tested the Wolfcamp “A”, with a

total of six horizontal wells

  • The next horizontal well targets the Wolfcamp “B” (spud

date: mid-September)

  • Nearby operators are targeting multiple benches: Jo

Mill, Upper Spraberry, Lower Spraberry, Wolfcamp A, Wolfcamp B, and Wolfcamp D (Cline)

  • Recent horizontal results point to potential IRRs in

excess of 100% for a one MMBoe type curve(1)

– North Midland Basin average IRRs are projected at 38% for ~650 Mboe type curve(1)

  • W&T’s has 25,730 net acres at Yellow Rose

– 150+ locations(2) X 305 MBoe EUR equals 45.8 million Boe of resource potential per targeted horizontal bench

Permian Basin Potential – Horizontal Wells

(1) Global Hunter Securities, “Permian Delineation Guide”, 8/26/13 (2) Location count of 150 is used only as an example, actual location count may vary per targeted horizontal zone

9,000 ft 10,000 ft 11,000 ft

Wolfcamp A Wolfcamp B Upper Spraberry

3+ target zones 1 target zone 2 target zones 2 target zones

Wolfcamp D (Cline)

Current industry target benches

Lower Spraberry

Additional potential in deeper zones

Jo Mill

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Untapped Reserve Growth Potential (as of year end 2012)

Focusing only on vertical downspacing to 20 acres and three horizontal benches, there are potentially ~220 MMBoe of unbooked reserves at Yellow Rose

Above figures assume a net EUR for verticals of 100 MBoe and a net EUR for horizontals of 305 MBoe. Estimated potential unbooked locations are: 80 acre – 33, 40 acre – 260, 20 acre – 600, WC “A” – 125, WC “B” – 150, and Cline – 150. These figures are speculative and are subject to revision.

3.3 26.0 60.0 38.1 45.8 45.8

0.0 50.0 100.0 150.0 200.0 250.0

Potential Reserve Growth at Yellow Rose

(potential reserve additions are in MMBoe)

80 acre 40 acre 20 acre Wolfcamp "A" Wolfcamp "B" Cline Bench ~220 MMBoe of potential reserve additions

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Midland Basin Activity Continues to Move North

  • Early efforts were

focused on the southern portion of the Midland Basin.

  • Prominent players are

now pushing the northern boundaries of the play.

  • Many of the new data

points offset W&T’s acreage

  • Recently acquired

acreage by others suggests heightened interest in the area

Source: Global Hunter Securities, Permian Delineation Guide - August 26, 2013 WTI “Yellow Rose”

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Latest Horizontal Results Near W&T Acreage

FANG UL III 4-1H

Wolfcamp “B” IP rate: 613 Boepd Lateral: 4,051

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STAR Prospect (WI: 97.6%)

  • Low entry cost, pure exploration play
  • Currently ~147,900 net acres in six East Texas counties (St.

Augustine, Shelby, Sabine, Nacogdoches, Angelina, and Jasper) with ongoing lease acquisition

  • Targeting oil in the James Lime formation @ ~8,500 ft TVD

Current Activity

  • Continue to delineate the acreage. Planning for a 5th well on

the acreage in the 4th quarter of 2013.

  • Based upon results of 5th well, additional wells may follow

Key Points for Star Prospect

  • Targeted cost per well ~ $7 million with targeted IP of up to

833 Boepd per well

  • No reserves currently booked for Star acreage at this time
  • Gross resource potential of up to 50 MMBoe

Exploration - Onshore

East Texas Exploration

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  • W&T has proven acquisition criteria

– Properties generate cash flow, are financeable, and have identified upside

  • We are a preferred buyer in the Gulf of Mexico

– Over 30 years of proven experience for safe operations – Strong liquidity provides the basis to seek numerous opportunities

  • High deal flow creates even more opportunity

– We continue to see more quality opportunities come to the market both

  • nshore and offshore

– W&T has closed ~$2.1 billion dollars worth of acquisitions since 2006

  • Strong history of creating value by increasing production and/or

reserves from the acquired assets

Balance – The Acquisition Component

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  • Revolving bank credit facility with $800 million borrowing base

– Amount available under credit facility(1) ~ $635 million – Cash balance(1) ~ $47.7 million – 20 banks in our current credit facility with additional capacity

  • Adjusted EBITDA for first six months of 2013 - $ 311.1 million
  • Current revolver matures in 2015 and bonds mature in 2019

– Bonds are currently trading(2) at $107.25 with a yield-to-worst of 6.279%

  • Added more oil hedges to protect the budget (see appendix for full disclosure)

– Average swap price(3) for 2H 2013: Brent - $103.06, WTI - $97.32 – Average swap price(3) for 2014: Brent - $97.37, WTI - $97.27

  • Access to capital markets

Liquidity Available for Further Growth

(1) Cash on hand and available revolver balance as September 24, 2013 (2) Bond pricing and YTW are quotes as of 9/24/13 (3) Prices reflect weighted averages for both Brent and WTI based swaps

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$0 $100 $200 $300 $400 $500 $600 $700 2010 2011 2012

  • Adj. EBITDA

CAPEX, Excl. Acquisitions Acquisition CAPEX 31

Drilling Within Cash Flow

($ in millions)

Historically, we have not borrowed money for drilling

2012 was the first full year of significant onshore drilling activity for W&T

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SLIDE 33

32 * Yield is calculated as total dividends for the year, divided by the closing stock price on the last day of the respective year. **Peers include: Apache, Bill Barrett, Cabot Oil & Gas, Comstock, Energy XXI, Forest Oil, McMoran, Newfield, Sandridge, Swift Energy, Stone Energy and SM Energy.

  • In 2012, we had a dividend yield* of

6.9%, which compares to a peer average of 0.2% **

  • Quarterly dividend has been

increased four times since going public

  • Paid a special dividend five of the

last six years, with two special dividends paid in 2012

W&T currently pays a quarterly dividend of $0.09 per share

Returning Cash to Investors

$0.51 $0.36 $0.12 $0.80 $0.79 $1.11 $- $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 2007 2008 2009 2010 2011 2012

Dividends per share

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SLIDE 34

10 20 30 40 50 60 WTI 2 3 4 5 6 7 8 9 10 11 12 13

53.8%

Insider Ownership

33

Aligned Interests: Shareholder View

*Peers include: Apache, Bill Barrett, Cabot Oil & Gas, Comstock, EPL, Energy XXI, Forest Oil, Newfield, Sandridge, Swift Energy, Stone Energy and SM Energy.

*Average inside ownership among peers is 2.9% vs. W&T at 53.8%

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How We Provide Value to Our Investors

  • Focused on organic growth through the drill bit

– 2013 Revised CAPEX Budget focused 60% on exploration – Disciplined approach: drill within cash flow

  • Exploration and Development both Onshore and Offshore

– Offshore activity roughly 2/3rds of budget, onshore activity 1/3rd

  • Company focused on free cash flow generation

– 2013 mid-year Adjusted EBITDA of $311.1 million

  • Maintains strong liquidity for acquisition opportunities

– Borrowing base under credit facility is $800 million

  • Continue to return cash to our investors

– Quarterly dividend of nine cents per share – Total dividends per share of $1.11 in 2012 with a yield of 6.9%

  • Management Team

– Incentivized and experienced

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APPENDIX

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The following table presents a reconciliation of our consolidated net income to consolidated EBITDA to Adjusted EBITDA:

We define EBITDA as net income (loss) plus income tax expense (benefit), net interest expense (which includes interest income), depreciation, depletion, amortization and accretion and impairment of oil and natural gas properties. Adjusted EBITDA excludes the loss on extinguishment of debt and the unrealized gain or loss related to our derivative
  • contracts. Although not prescribed under GAAP, we believe the presentation of EBITDA and Adjusted EBITDA provide useful information regarding our ability to service debt and
fund capital expenditures and they help our investors understand our operating performance and make it easier to compare our results with those of other companies that have different financing, capital and tax structures. EBITDA and Adjusted EBITDA should not be considered in isolation from or as a substitute for net income, as an indication of
  • perating performance or cash flow from operating activities or as a measure of liquidity. EBITDA and Adjusted EBITDA, as we calculate them, may not be comparable to
EBITDA and Adjusted EBITDA measures reported by other companies. In addition, EBITDA and Adjusted EBITDA do not represent funds available for discretionary use.

Reconciliation of Net Income to EBITDA

Year Ended December 31, Six Months Ended June 30, ($ in thousands) 2010 2011 2012 2012 2013 Net income $ 117,892 $ 172,817 $ 71,984 $ 56,785 $ 49,014 Income tax expense 11,901 91,517 47,547 36,134 27,325 Net interest expense 36,996 42,432 49,979 22,094 37,815 Depreciation, depletion, amortization and accretion 294,100 328,786 356,232 174,432 208,767 EBITDA 460,889 635,552 525,742 289,445 322,921 Adjustments: Unrealized derivatives loss (gain) 9,511 (11,770) 6,289 (16,322) (11,783) Royalty relief recoupment (24,881) Transportation allowance for deepwater production 4,687 Loss on extinguishment of debt 22,694 Litigation Accrual 10,250 8,300 Adjusted EBITDA $ 450,206 $ 646,476 $ 542,281 $ 281,423 $ 311,138
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2013 Guidance

GUIDANCE DOES NOT INCLUDE ACQUISITIONS

(1) Revised Full Year guidance provided in the Q2 2013 earnings release (2) Reflects the statutory tax rate

Third Quarter Full Year(1)

Estimated Production

2013 2013

Oil and NGLs (MMBbls) 2.0

  • 2.3

9.0

  • 9.5

Natural Gas (Bcf) 10.1

  • 11.5

47.4

  • 49.5

Total (Bcfe) 22.2

  • 25.2

101.3

  • 106.5

Total (MMBbls) 3.7

  • 4.2

16.9

  • 17.7

Third Quarter Full Year

Operating Expenses

2013 2013

Lease operating expenses $ 68

  • $ 77

$ 249

  • $ 275

Gathering, transportation, & production taxes $ 7

  • $ 8

$ 26

  • $ 31

General & administrative $ 21

  • $ 24

$ 78

  • $ 86

Income tax rate (1) 36% 36%

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2012 Year End Reserves

(1) In accordance with guidelines established by the SEC, our proved reserves as of December 31, 2012 were determined to be economically producible under existing economic conditions, which requires the use of the unweighted arithmetic average of the first-day-of-the-month price for oil and gas for the period January 2012 through December 2012. Also note that the present value of our total proved reserves only, discounted at 10% (referred to as “PV-10”) is a non-GAAP financial
  • measure. See “Non-GAAP Financial Measure” below. For 2012, proved reserves and PV-10 were calculated using average prices of $98.13 per Bbl for oil, $1.13 per
gallon for natural gas liquids and $2.77 per Mcf for natural gas, as adjusted for energy content for natural gas, quality, transportation fees and regional price
  • differentials. The proved reserves and PV-10 for the 2011 period were calculated using average prices of $97.36 per Bbl for oil, $1.22 per gallon for natural gas liquids
and $4.11 per Mcf for natural gas, as adjusted for energy content for natural gas, quality, transportation fees and regional price differentials. (2) PV-10 values for Probables and Possibles are unrisked values and are not comprehensive in the inclusion of all current projects.

As of December 31, 2012 Total Equivalent Reserves Classification of Proved Reserves Oil (MMBbls) NGLs (MMBbls) Natural Gas (Bcf) Oil Equivalent (MMBoe) Natural Gas Equivalent (Bcfe) PV-10

(1)

(Millions) Proved developed producing 24.7 8.9 173.9 62.6 375.4 $ 1,664 Proved developed non-producing 10.7 2.1 69.5 24.3 145.8 777 Total proved developed 35.3 11.0 243.4 86.9 521.2 2,441 Proved undeveloped 19.5 4.2 41.6 30.6 183.9 379 Total proved 54.8 15.2 285.1 117.5 705.1 $ 2,820 Probables(2) 18.1 4.3 96.3 38.4 230.3 $ 633 Possibles(2) 37.9 3.9 243.1 82.4 494.4 $ 1,290

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39

Financial Commodity Derivatives

(1) All figures reflect weighted averages for the specified period

2013 Swaps Brent Swaps WTI Swaps Barrels Avg Swap Barrels Avg Swap Month Per Day Price Per Day Price July 5,400 $ 104.99 2,000 $ 97.00 August 4,400 103.85 3,000 97.27 September 3,400 101.98 1,000 97.00 October 3,200 101.98 3,000 97.37 November 3,200 101.98 7,000 97.39 December 3,200 101.98 7,000 97.37

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40

Financial Commodity Derivatives

(1) All figures reflect weighted averages for the specified period

2014 Swaps Brent Swaps WTI Swaps Barrels Avg Swap Barrels Avg Swap Month Per Day Price Per Day Price January 2,000 $ 97.38 9,000 $ 97.44 February 2,000 97.38 9,500 97.31 March 2,000 97.38 7,000 97.43 April 1,900 97.38 6,500 97.32 May 1,900 97.38 5,000 97.06 June 1,900 97.38 3,500 97.06 July 1,800 97.38 3,000 97.00 August 1,800 97.38 2,000 97.01 September 1,800 97.38

  • October

1,700 97.37

  • November

1,700 97.37

  • December

1,700 97.37

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41

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

  • ur 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

  • il and natural gas; (4) increases in production growth and proved reserves; (5) operating costs such as lease
  • perating 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

  • bligation 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, 2012, 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.

Forward-Looking Statement Disclosure

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Nine Nine Gre Green enway Pl ay Plaza aza, , Suite Suite 30 300 Houston, Houston, TX TX 77046 77046 Main ain li line ne: : 71 713-626 626-8525 8525 Fa Fax: 713 x: 713-626 626-8527 8527 In Investor vestor Relation elations: s: 71 713-297 297-8024 8024 ww www.wtoff w.wtoffshore. shore.com com www.i .investorre nvestorrelations@ lations@wtof toffsho fshore.co re.com