Johnson Rice Energy Conference
New Orleans – October 2nd, 2013
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
Johnson Rice Energy Conference
New Orleans – October 2nd, 2013
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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Revised 2013 Capital Expenditures Budget
– 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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Current Activity for W&T Offshore
MC 738/782 operated by Noble Energy
well
deepwater discoveries
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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
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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Multiple Avenues to Achieve Organic Growth
─ Permian & East Texas
─ Proved Reserves(1)
─ Est. Daily Sales Volumes(2)
GOM DEEPWATER ONSHORE TEXAS GULF OF MEXICO SHELF
─ Deepwater (over 500’)
─ Proved Reserves(1)
─ Est. Daily Sales Volumes(2)
─ GOM Shelf (under 500’)
─ Proved Reserves(1)
─ Est. Daily Sales Volumes(2)
(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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Balance – The Offshore Component
W&T has continued to grow its footprint in the Gulf of Mexico through acquisitions and leases sales
acquired from Newfield (59 exploratory blocks)
recent lease sales
MC698 “Big Bend”, MC699 “Troubadour”, and MC 738/782 “Dantzler”
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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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%)
reservoir in Lower Miocene against
and 1,200’ of significant sand in the target section.
water to a target depth of 19,150’
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%)
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”
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)
75%
*All figures are operator (NBL) estimates
SS 349 “Mahogany”
Continued Sub-Salt Exploration & Development Success
(WI: 100%, NRI: 83.3%)
‒ Primary Field Pay is P-Sand ‒ Multiple producing horizons recently discovered
feet of water on GOM shelf
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
SS 349 “Mahogany” A-14 Well
Deep Shelf, Sub-Salt Discovery
(WI: 100%, NRI: 83.3%)
discovered new reserves in the T-sand and logged significant additional pay in four additional hydrocarbon bearing zones
‒ 3,870 Boepd net after royalties
(4,644 gross Boepd, 77% crude oil)
‒ 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:
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
SS 349 “Mahogany” A-15 Well
Deep Shelf, Sub-Salt Exploration
(WI: 100%, NRI: 83.3%)
five separate sands (N,O,P,Q,Q5)
approximately one month for the A-12 well workover
15,500’
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%)
reserves in the Lentic 1 sand by drilling a side-track from the existing A-2 well bore
East Cameron 321 field is situated 97 miles off the coast
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.
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
NPV ~ $50 -$150 MM
MP 108 B-1
(WI: 100%, NRI 82%)
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.
(80% gas, 10% oil, 10% NGLs)
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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Development – GOM Shelf
High Island 21 (WI: 100%, NRI: 81%)
targeting the LH 20 sands
20 sand plus additional upside pay in LH-16 exceeding original expectations
West Cameron 73 #2 (WI: 30%, NRI: 24%)
well drilled in 2012 which logged over 150 feet of pay across multiple zones
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:
including a significant discovery at our SS 349 “Mahogany” field in the T- Sand, with three additional upside pay zones encountered
drilling locations in our premier
“Mahogany”
raising full year guidance for oil and NGLs
exploratory well in two years
Offshore Projects – Solid Results, More to Come
– Current and Upcoming Projects:
EC 321 A-2 ST, both seeking new oil reserves
HI 21 A-1, and WC 73 #2 wells this year
development (MC 698 & MC 699) project before year end
SS 349 “Mahogany” field
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Balance – The Onshore Component
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%)
project with long-life reserves
vertical wells. Currently running two rigs.
its Yellow Rose prospect. Total net acreage: 25,730.
Key Points for Yellow Rose
results are expected before year end
production”
position and have utilized micro-seismic to enhance
Exploration and Development - Onshore
Yellow Rose avg. July production mix
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:
– Some 80 acre locations associated with new acreage still are unbooked
target net EUR of 100 Mboe per well(1) – Up to 86 million barrels of unbooked reserves on verticals alone(2)
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 field20 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:
total of six horizontal wells
date: mid-September)
Mill, Upper Spraberry, Lower Spraberry, Wolfcamp A, Wolfcamp B, and Wolfcamp D (Cline)
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)
– 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 zone9,000 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
focused on the southern portion of the Midland Basin.
now pushing the northern boundaries of the play.
points offset W&T’s acreage
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%)
Augustine, Shelby, Sabine, Nacogdoches, Angelina, and Jasper) with ongoing lease acquisition
Current Activity
the acreage in the 4th quarter of 2013.
Key Points for Star Prospect
833 Boepd per well
Exploration - Onshore
East Texas Exploration
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– Properties generate cash flow, are financeable, and have identified upside
– Over 30 years of proven experience for safe operations – Strong liquidity provides the basis to seek numerous opportunities
– We continue to see more quality opportunities come to the market both
– W&T has closed ~$2.1 billion dollars worth of acquisitions since 2006
reserves from the acquired assets
Balance – The Acquisition Component
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– Amount available under credit facility(1) ~ $635 million – Cash balance(1) ~ $47.7 million – 20 banks in our current credit facility with additional capacity
– Bonds are currently trading(2) at $107.25 with a yield-to-worst of 6.279%
– 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
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
$0 $100 $200 $300 $400 $500 $600 $700 2010 2011 2012
CAPEX, Excl. Acquisitions Acquisition CAPEX 31
Drilling Within Cash Flow
($ in millions)
Historically, we have not borrowed money for drilling
2012 was the first full year of significant onshore drilling activity for W&T
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.
6.9%, which compares to a peer average of 0.2% **
increased four times since going public
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
10 20 30 40 50 60 WTI 2 3 4 5 6 7 8 9 10 11 12 13
53.8%
Insider Ownership
33Aligned 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
– 2013 Revised CAPEX Budget focused 60% on exploration – Disciplined approach: drill within cash flow
– Offshore activity roughly 2/3rds of budget, onshore activity 1/3rd
– 2013 mid-year Adjusted EBITDA of $311.1 million
– Borrowing base under credit facility is $800 million
– Quarterly dividend of nine cents per share – Total dividends per share of $1.11 in 2012 with a yield of 6.9%
– Incentivized and experienced
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The following table presents a reconciliation of our consolidated net income to consolidated EBITDA to Adjusted EBITDA:
We define EBITDA as net income (loss) plus income tax expense (benefit), net interest expense (which includes interest income), depreciation, depletion, amortization and accretion and impairment of oil and natural gas properties. Adjusted EBITDA excludes the loss on extinguishment of debt and the unrealized gain or loss related to our derivativeReconciliation of Net Income to EBITDA
Year Ended December 31, Six Months Ended June 30, ($ 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 $ 311,13837
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
9.0
Natural Gas (Bcf) 10.1
47.4
Total (Bcfe) 22.2
101.3
Total (MMBbls) 3.7
16.9
Third Quarter Full Year
Operating Expenses
2013 2013
Lease operating expenses $ 68
$ 249
Gathering, transportation, & production taxes $ 7
$ 26
General & administrative $ 21
$ 78
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 financialAs 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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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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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
1,700 97.37
1,700 97.37
1,700 97.37
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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
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
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
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
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
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