Jefferies 2015 Energy Conference November 11-12, 2015, Houston - - PowerPoint PPT Presentation

November 11-12, 2015, Houston

Jefferies 2015 Energy Conference

Financial & Operations Overview

W&T Offshore Overview (NYSE: WTI)

See the slide titled “Reconciliation of Net Income to Adjusted EBITDA” for an analysis of the change between Net Income and Adjusted EBITDA

Highlights

Twelve Months Ended 9/30/15 12/31/14

Daily Production

9/30/15 9/30/14

Oil (MBbls/d) 21.2 19.6 NGLs (MBbls/d) 4.5 5.7 Natural Gas (MMcf/d) 129.9 135.4 Total (MBoe/d) 47.4 47.8 Total (MMcfe/d) 284.1 286.8

Revenue $ 599.9 $ 948.7 Adjusted EBITDA $ 276.8 $ 569.2

Nine Months Ended

43% 11% 46%

Oil NGLs

• Nat. Gas

Proved Reserves of 82.7 (MMBoe) at 12/31/14

Reserves and Reserves Mix reflect adjustments to exclude reserves attributable to the Spraberry Field, which was sold in October 2015.

Reserves Mix

• Drilling success rate offshore has

been 100% the last two years

• Total production rate is steady year-
• ver-year, while oil is up 12% based on

continued success with the drill bit. Achieved despite 60% drop in capital spending

• In first nine months of 2015, proved

reserves, excluding Yellow Rose, declined only slightly, despite a 40% decline in crude oil prices and a 30% decline in natural gas prices

• Reserve additions from two wells at

Medusa and one well at EW 910 (and upward revisions at Mahogany ) were big

• contributors. However, Big Bend &

Dantzler came on line in the 4th quarter

• Production exit rate estimated at

50,000 Boe per day with 49% from oil

1

2

Premium Assets in the Gulf of Mexico

Gulf of Mexico Shelf

• ~ 561,000 gross acres (~392,000 net acres)
• ~ 56% of daily production
• 1P reserves of 53.8 MMBoe
• 2P reserves of 73.9 MMBoe
• Future growth potential from sub-salt prospects identified with advanced seismic

Deepwater Gulf of Mexico

• ~ 384,000 gross acres (~179,000 net acres)
• ~ 38% of daily production
• 1P reserves of 28.9 MMBoe
• 2P reserves of 50.9 MMBoe
• Substantial upside from numerous projects (Big Bend, Dantzler, Medusa, EW 910 and
• thers)

Notes:

• Reserves are as of 12/31/2014
• The estimates “% of daily production” are for the nine months ended September 30, 2015 and

exclude approximately 6% which is attributable to the Yellow Rose Field located in the Permian

• Basin. The Company closed on the sale of this field on October 15, 2015

3

Recent Events Enhance Liquidity

Sale of Yellow Rose Field in Permian Basin Yielded Net Proceeds of ~$376 Million

• Closing occurred October 15, 2015
• A portion of the proceeds were used to pay down the revolving bank credit

facility to zero. Remaining funds will provide additional liquidity for future

• perations and acquisitions
• Retained one to four percent sliding scale ORRI in the field
• Liquidity improves to $485 million
• Amended bank credit agreement and revised Borrowing Base

Current deepwater projects are adding substantial production throughout 2015 & beyond

• Expect an exit rate for 2015 of about 50,000 Boe per day, 49% oil

Corporate Overview

• We focus on projects that will grow reserves, increase production and

generate profit – Exploration

• We are focusing more and more on deepwater opportunities

– Acquisitions

• Requirements are:

– Cash flow – Upside drilling – Workover / Recompletion / Facility upgrades – Development & Re-Development of existing assets

• Utilizing new seismic data
• Historically, W&T’s EBITDA margins are in the range of 60 – 70%
• With over 30 years of experience, we are a safe, efficient and reliable operator

4

5

Probable and Possible Reserves Fuel Growth to Proved Reserves and Future Value

6

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

Probables and Possibles provide hidden value and significant upside

(1) The Company sold all of its interests in the Spraberry Field in October 2015. The above chart and amounts reflect estimates for reductions due to such sale

• f reserves.

(2) Except for “Cumulative CAPEX”, figures reflect year-end 2014 SEC price case. Cumulative CAPEX reflect estimates as of 6/30/15. (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. (4) Probable and possible cases that are largely associated with producing wellbores and require no additional future CAPEX requirements.

Incremental Value Increases with CAPEX $774 Million

PV-10 Created with No Future CAPEX

$1.2 Billion

PV-10 Created with Primarily PNP / PUD CAPEX

$2.8 Billion

Total

$0 $0 $209 $225 $264 $451

Cumulative CAPEX

DEEPWATER

Gulf of Mexico

8

Deepwater Acquisitions Drive Growth

2010 2010 2013 2012 Callon $82 million

• Medusa (prod. is 88% oil)
• 1P – 2.1 MMBoe
• 2P – 4.3 MMBoe
• 3P – 6.5 MMBoe
• Two exploration wells brought on

production in June 2015 . September combined gross rate is 13,000 Boepd

Newfield $206 million

• 78 lease blocks
• 65 deepwater blocks
• 1P – 4.7 MMBoe
• 2P – 6.9 MMBoe
• 3P – 9.3 MMBoe
• Paid out in Nov. 2014

Shell Deepwater $116 million

• Tahoe
• Droshky
• 1P – 6.1 MMBoe
• 3P – 12.1 MMBoe
• Paid out in Nov. 2012

Total $115 million

• Matterhorn
• Virgo
• 1P – 8.6 MMBoe
• 2P – 15.3 MMBoe
• 3P – 24.3 MMBoe
• Paid out in August 2011

2014 Woodside $51 million

• Neptune (prod. is 87% oil)
• 27 deepwater blocks
• 1P – 1.3 MMBoe
• 2P – 2.9 MMBoe
• Initial exploratory well placed

into production in 2014 4th Qtr

Through acquisitions and lease sales, W&T now holds interests in ~ 384,000 gross / 179,000 net acres in the deepwater of the Gulf of Mexico, approximately 41% of total net offshore acres

Deepwater GOM Overview

2015 Current Project Activities Other Significant Deepwater Producing Leases Deepwater Developed Leases Undeveloped Deepwater Exploration Leases

MC 538/582 “Medusa”

Cum Gross Prod: 66.9 MMBoe

• Avg. Gross Prod: 17.1 MBoepd

Non-operated

MC 243 “Matterhorn”

Cum Gross Prod: 26.6 MMBoe

• Avg. Gross Prod: 3.3 MBoepd

Company Operated

VK 783/784 “Tahoe”

Cum Gross Prod: 98.2 MMBoe

• Avg. Gross Prod: 5.4 MBoepd

Company Operated

GB 258 “Powerplay”

Cum Gross Prod: 11.8 MMBoe

• Avg. Gross Prod: 4.0 MBoepd

Non-operated

VK 822/823 “Virgo”

Cum Gross Prod: 22.3 MMBoe

• Avg. Gross Prod: 1.5 MBoepd

Company Operated

MC 800 “Gladden”

Cum Gross Prod: 5.3 MMBoe

• Avg. Gross Prod: 2.4 MBoepd

Company Operated

EW 910

Cum Gross Prod: 15.0 MMBoe

• Avg. Gross Prod: .4 MBoepd

Company Operated

MC 782 “Dantzler”

Non-operated

MC 698 “Big Bend”

Non-operated

MC 506 “Wrigley”

Cum Gross Prod: 8.6 MMBoe

• Avg. Gross Prod: 2.0 MBoepd

Company Operated

AT 574/575/618 “Neptune”

Cum Gross Prod: 36.6 MMBoe

• Avg. Gross Prod: 11.3 MBoepd

Non-operated

9

“Avg. Gross Prod” is an estimate of recent daily gross average production. The above production amounts are as of and for the month of September 2015 except for EW 910 which is July 2015.

10

Deepwater Success – MC 698 “Big Bend”

MC 698 Big Bend

(WI: 20%; NRI: 16.70%)

• Located about 165 miles SSE of New

Orleans, LA

• Gross resource estimate of 30 to 65

MMBoe with potential additional 30 – 50 MMBoe (P75 – P25)(1)

• Currently producing at a gross rate in

excess of 20,000 Boe per day

• Sub-sea development with tie-back to

Thunder Hawk Platform

MC 698 “Big Bend”

• il discovery

(1) Represents operator’s published gross production and reserve assumptions.

First production on October 26, 2015

11

Deepwater Success – MC 782 “Dantzler”

Dantzler #1 and Dantzler #2

• il discoveries

MC 782 “Dantzler”

(WI: 20%; NRI: 16.25%)

• Located about 160 miles SSE of New

Orleans, LA

• Two oil discovery wells
• Two high-quality Miocene reservoirs
• Gross resource estimate of 65 to 100

MMBoe (P75 – P25 case)(1)

• Tie-back with Big Bend to nearby

Thunder Hawk Platform

• Both wells are dual completions that

will produce from multiple reservoirs

(1) Represents operator’s published gross production and reserve assumptions.

First production on November 1, 2015

12

Rio Grande Loop System Enhances Return on Investment

Dantzler #1 & #2 Big Bend

Subsea tie-back from Big Bend and Dantzler fields established first production to the host “Thunder Hawk” platform in October 2015 Combined rate from Big Bend and Dantzler expected to reach in excess

• f 8,000 barrels per day by year-end 2015, net to our interest (~81% oil)

Thunder Hawk Platform

13

MC 538 “Medusa” – 2015 Expansion Activities

Medusa (MC 538/582) acquired via the Callon Transaction in 2013

(WI: 15%; NRI: 15%*)

Expansion activity recently completed at Medusa

• The SS 6 well reached TD at year-end encountering net

pay in both primary zones. The well logged over 180’ of net pay. The SS 6 well was completed in April

• The SS 7 well was drilled to TD in early March and

encountered over 100’ of net pay. The SS 7 well was completed in June

• The SS 6 and SS 7 wells produced at average gross

rates in September 2015 of about 6,514 and 6,483 Boe per day, respectively (a combined net rate to W&T of ~1,950 Boe per day)

* This provides for royalty suspension

MC 538 / 582

(WI: 15%; NRI: 15%*)

• Medusa includes ownership in SPAR as well

as dry tree and subsea wells

• Amplitude play with no false positives
• Second Development phase completed
• Three additional prospects with similar

amplitudes have been identified

• Medusa SPAR is also host facility for the

W&T owned “Gladden” production at MC 800

Upside Opportunities at Medusa

* This providesfor royalty suspension

MEDUSA SS9 Prospect MEDUSA SS6 Producer MEDUSA SS7 Producer MEDUSA SS8 Prospect MEDUSA SS10 Prospect

14

15

Growth at Neptune Field

Neptune Field

(WI: 20.0%, NRI: 17.5%)

• Atwater Valley 574, 575 and 618
• September 2015 estimated gross average daily

production rate of 11,290 Boe (1,976 Boe net to W&T’s interest) (~88% oil)

• Water depth of 6,200’; TLP is situated on Green

Canyon Block 613 where the water depth is about 4,250’

Current Activity:

• Field Optimization Phase: Gas lift flowline system

to increase production and reserves by extending field life

16

Neptune Field and Other Woodside Acquisition Upside

Neptune Upside

• Drilling – Northern half of field has never been tested due

to the difficulty of seismic imaging under the salt

• verhang. Significant upside exists to potentially double

the size of the field if future exploration efforts are successful.

• Gas Injection - Operator has implemented a gas-flowline

injection system to increase production and recovery of existing reservoir. Initial results are encouraging. Additional Woodside Acquisition Upside

• Additional drilling potential exists on other exploration

leases (a total of 24 additional deepwater blocks acquired).

17

Multi Well Potential at Ewing Bank 910

Current Status

• Initial two well drilling program in a 50% / 50% joint

venture during 2015. Estimated NRI is about 41.67% net

• The first well, the ST 320 A-5 ST, was drilled to a TVD of

16,000’. The well logged 160 feet of gross hydrocarbon interval

• The A-5 ST commenced production on October 12, 2015

and is currently flowing at about 2,150 Boe per day gross (~900 Boe per day, net)

• Expect recovery from well to exceed our pre-drill

estimates.

• The A-8 exploratory well is currently drilling and estimated

to be a larger reserve target than the A-5 ST well, based

• n existing seismic data

Additional Upside with Improved Seismic

• Additional wells in inventory
• Prospective 35-70 MMBoe (gross)
• We have additional drilling locations as a result of our
• ngoing G&G review of new WAZ seismic data

EW 910 Field

• Water depth of 560 feet
• Cumulative field production of

~15 MMBoe (79% oil) as of September 2015

18

GOM Deepwater – MC 243 “Matterhorn”

Deepwater TLP moored in 2,552 feet water

Mississippi Canyon 243

WI: 100%

• Cumulative Production (through August

2015): 26.6 Million Boe

• Acquired in 2010
• Active optimization and enhancement since

acquisition

• September 2015 average rate: ~3,271

Boepd

Key Events

• Initiated eastern sector waterflood 2014
• Waterflood response in late 2014 … poised

for reserve expansion in 2015+

• Expand waterflood to west in 2016

19

Matterhorn Phase I Water Injection Response

Water Flood Response:

• Response: definitive and quick
• Over 980% increase in rate
• Rate has stabilized at ~ 1.1

MBoepd

• Project NPV: $50 - $170 million
• De-risks PHASE II (West Area)

Low Risk Exploitation Optimization and Investment; successful water flood has set path for reserves expansion, value creation and repeatability into western field area. Gas Rate (Mcfpd)

Water Flood and Pressure Maintenance

• Began injection

September 2014

OIL RATE

(Bopd)

Matterhorn Phase II Water Injection Program

Eastern Waterflood

• OOIP: 28 MMBO
• Total Recovery Factor: 25%
• Reserves added: 2.0 MMBO
• NPV: $50MM+

Western Waterflood

• OOIP: 34 MMBO
• Total Recovery Factor: 32%
• Additional Reserves: 3.7 MMBO
• NPV: $50MM to $240MM
• Lower risk due to results of eastern waterflood
• More efficient capital project since injection

well in place

• Currently waiting on A-7 well to deplete in

current reservoir Future Opportunity: Western Pressure Maintenance Eastern waterflood

20

SHELF

Gulf of Mexico

22

EC 321

Cum Gross Prod: 105.6 MMBoe

• Avg. Gross Prod: 1.2 MBoepd

Company Operated

BA A133

Cum Gross Prod: 152.8 MMBoe

• Avg. Gross Prod: 3.2 MBoepd

Company Operated

MP 98 & MP 108

Cum Gross Prod: 52.3 MMBoe

• Avg. Gross Prod: 3.7 MBoepd

Company Operated

MP 283

Cum Gross Prod: 14.2 MMBoe

• Avg. Gross Prod: 1.4 MBoepd

Company Operated

SS 208

Cum Gross Prod: 455.8 MMBoe

• Avg. Gross Prod: 8.7 MBoepd

Company Operated

SS 222

Cum Prod: 213.5 MMBoe

• Avg. Gross Prod: 1.0 MBoepd

Non-operated

SS 349/359 “Mahogany”

Cum Gross Prod: 40.4 MMBoe

• Avg. Gross Prod: 10.3 MBoepd

Company Operated

ST 228

Cum Gross Prod: 11.0 MMBoe

• Avg. Gross Prod: 6.9 MBoepd

Company Operated

Fairway Field & Yellowhammer Plant

Cum Gross Prod: 127.1 MBoe Avg. Gross Prod: 6.4 MBoepd Company Operated Significant Shelf Producing Leases Shelf Developed Leases Undeveloped Shelf Exploration Leases

“Avg. Gross Prod” is an estimate of recent daily gross average production. The above production amounts are as and for the month of September 2015 except for the SS 208 and ST 228 which are July 2015.

Well Positioned on the Shelf

23

Working to Identify Opportunities to Replicate Past Success on the Shelf

Success adding value to GOM shelf properties demonstrates the upside potential in known fields

• Mahogany field production growth of over 500% since 2011
• Recent activity on EC 321, BA 133 and Fairway

Working to enhance our inventory of projects for when market conditions improve

• Analyzing newly acquired advanced seismic data over portions of our shelf

acreage to identify future drilling opportunities

• Through the drilling of eight wells at Mahogany, we have obtained improved

understanding of sub-salt targets

By applying the lessons of success from Mahogany and reviewing advanced seismic data on other targeted lease blocks, we anticipate Mahogany-like opportunities exist elsewhere on the Shelf as well as in the Deepwater

24

Exploration Success at Ship Shoal 349 (“Mahogany”) Since 2011

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

(WI: 100%, NRI: 83.3%)

• Have substantially expanded the size and

depth of the field since 2011

• Mahogany is a multi-horizon production

‒ Eight wells drilled and completed since 2011 ‒ Primary Field Pay is P-Sand ‒ T-Sand 2013 discovery 3,000’ deeper from P-Sand extends the “known depth”

• f the oil column
• Average production rate for :

‒ September 2015 for the field ~8,600 Boepd net (~10,262 gross). ‒ Full Year 2011 for the field ~1,620 Boepd net (~ 1,950 gross)

Mahogany Wells Drilled Before and After Mid-2011

25

Mahogany’s Prolific “P” & “T” Sand

• Mahogany's primary field pay “P” Sand has cumulatively produced approximately 31 million Boe since 1997 from multiple wells
• “T” Sand is 3,000 feet deeper and better quality than “P” Sand
• Upside potential for the “T” Sand; Connected to very large pore volume position
• Seismic and reservoir data may identify additional productive sands or expand potential size of T-Sand

SS 349 A-14 “T” Sand Log SS 349 A-14 “P” Sand Log

P1 P2 P3 P4

26

Mahogany A-14 “T-Sand” – Strong & Stable Production

• Current Rate is 3,115 Boe net (~3,738 gross)
• Production is > 75% crude oil
• Cumulative production as of 10/15/15 ~ 2,169,000 Boe net (~2,603,000 Boe gross)
• Steady production indicates strong water drive and/or large reservoir
• Bottom hole pressure has been very constant

Cum Net Boe Boepd

27

Mahogany A-16 – Strong & Stable Production from “P-Sand”

• Initial Production on 10/28/14
• Current Rate is 1,865 Boe net (~2,238 gross)
• Production is > 80% crude oil
• Cumulative production ~ 671,000 Boe net (~805,000 Boe gross) as of 10/13/15

Cum Net Boe Boepd

Financial Overview

2015 Capital Focused on GOM Deepwater

GOM Deepwater: 84.5% $169.0 million

GOM Shelf: 7.5% $16.4 million Onshore: 6.7% $14.7 million

Seismic, Leasehold & Other: 3.9% $8.6 million

2015 Estimate of ~$220 Million

• Capital Expenditures will be a bit higher

than budget as development work has

• ccurred for all the successful wells in 2015
• Deepwater GOM development

expenditures at Big Bend and Dantzler include ~$97MM for the Rio Grande Loop system and Dantzler completion costs

• Two-well exploration program at

Deepwater Medusa includes ~$40MM to drill and complete the MC 538 SS7 and to complete the MC 538 SS6. Both have been completed and are producing at a combined gross rate of ~13.0 MBoepd (~2.0 MBoepd net) during September 2015

• Two-well exploration program at Deepwater

EW 910 includes ~$45MM for drilling and completing the ST 320 A-5 ST and EW 954 A-8

29

GOM Deepwater: 82.0% $180.3 million

30

2015 Spending Reduction Program

($ in millions)

• Significant reductions in 2015 spending.
• Capital Expenditures down by ~ 69%
• Lease Operating Expenses down by

~ 26%

• General & Administrative Expenses

down by ~ 14%

Reduction Program

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

31

Liquidity Status

• Revolving bank credit facility of $1.2 billion with a $350 million

borrowing base

– Sale of Yellow Rose Field closed in October 2015 and yielded net proceeds of ~$376 million. A portion of these proceeds were used to pay off the balance of

• ur revolving credit facility

– Amended revolving bank credit facility effective October 30, 2015 – Enhanced financial flexibility with certain covenants changed or eliminated from bank credit facility that matures in November 2018 – Borrowing base at $350 million effective October 30, 2015 – As of October 28, 2015, cash on hand (~ $135 million) and amount available under credit facility (~$350 million) results in total liquidity of $485 million – 20 banks in our current credit facility with additional capacity

• Senior Notes mature in 2019
• Second Lien Term Loan maturing in 2020

32

Investment Highlights Outstanding acquisition track record adds near-term value as well as growth through further exploration and development Deepwater success drives production growth and long- term value Excellent asset base provides opportunity to increase cash flow and add value

Appendix

Guidance

($ in millions)

34

Estimated Production Oil and NGLs (MMBbls) 2.3

• 2.5

9.3

• 10.3

8.9

• 9.9

Natural Gas (Bcf) 10.8

• 12.0

44.0

• 48.6

44.5

• 49.2

Total (Bcfe) 24.4

• 26.9

100.0

• 110.2

98.1

• 108.4

Total (MMBoe) 4.1

• 4.5

16.6

• 18.4

16.3

• 18.1

Operating Expenses Lease operating expenses 51 $

• 57

$ 219 $

• 242

$ 187 $

• 207

$ Gathering, transportation, & production taxes 5 $

• 6

$ 25 $

• 28

$ 20 $

• 22

$ General & administrative 17 $

• 19

$ 71 $

• 78

$ 71 $

• 78

$ Income tax rate (100%deferred) 3.6% 14.0% Fourth Quarter Prior Full Year 2015 2015 Revised Full Year 2015 12.0%

Reconciliation of Net Income to Adjusted EBITDA

($ in thousands)

35

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 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 operating performance or cash flow from

• perating 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
• ther companies. In addition, EBITDA and Adjusted EBITDA do not represent funds available for discretionary use.

2015 2014 2014 2013 2012 2011 Net income (loss) $ (1,026,484) $ (993,112) $ 21,710 $ (11,661) $ 51,322 $ 71,984 $ 172,817 Income tax expense (benefit) (183,511) (166,228) 12,825 ` (4,459) 28,774 47,547 91,517 Net interest expense 91,902 71,786 58,078 78,194 75,572 49,979 42,432 Depreciation, depletion, amortization and accretion 457,026 326,138 380,213 511,102 451,529 356,232 328,786 Impairment of oil and natural gas properties 954,850 954,850

• EBITDA

293,783 193,434 472,827 573,176 607,197 525,742 635,552 Adjustments: Derivatives loss (gain) (19,908) (9,153) 6,790 (3,965) 8,470 13,954 (1,896) Debt issuance costs write-off 1,973 1,973

• Contingent assessment provision

1,000 1,000

• Loss on extinguishment of debt
• 128
• 22,694

Contract Option Fee

• (9,062)
• Litigation Accrual
• 10,250
• Adjusted EBITDA

$ 276,849 $ 187,255 $ 479,617 $ 569,211 $ 606,733 $ 549,946 $ 656,350 Adjusted EBITDA Margin 46% 46% 64% 60% 62% 63% 68% Twelve Months Ended September 30, 2015 Nine Months Ended Sept. 30, Year Ended December 31,

2014 Year End Proved Reserves

36

1) In accordance with guidelines established by the SEC, our proved reserves as of December 31, 2014 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 2014 through December 2014. Also note that the PV-10 value is a non-GAAP financial measure. We refer to PV-10 as the present value of estimated future net revenues of estimated proved reserves as calculated by our independent petroleum consultant using a discount rate of 10%. This amount includes projected revenues, estimated production costs and estimated future development costs and excludes ARO. For 2014, proved reserves and PV-10 were calculated using average prices of $91.12 per barrel for oil, $34.63 per barrel for natural gas liquids and $4.265 per Mcf for natural gas, as adjusted for energy content for natural gas, quality, transportation fees and regional price differentials.

Classification of Proved Reserves Oil (MMBbls) NGLs (MMBbls) Natural Gas (Bcf) Oil Equivalent (MMBoe) Natural Gas Equivalent (Bcfe) % of total reserves PV-10 (1) (Millions) Proved developed producing 29.8 9.2 177.7 68.6 411.7 57% 1,903.0 $ Proved developed non-producing 5.9 1.5 43.4 14.6 87.8 12% 304.0 Total proved developed 35.7 10.7 221.1 83.3 499.5 69% 2,207.0 Proved undeveloped 26.0 5.1 33.8 36.7 220.4 31% 398.0 Total proved 61.7 15.8 254.9 120.0 719.9 100% $ 2,605.0

Forward-Looking Statement Disclosure

37

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, 2013, 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.

• Nine Greenway Plaza, Suite 300 • Houston, TX 77046
• Main line: 713-626-8525 • Fax: 713-626-8527
• Investor Relations: 713-297-8024
• www.wtoffshore.com • www.investorrelations@wtoffshore.com