Earnings Call Presentation May 2015

Transcription

1 Earnings Call Presentation May

2 FORWARD LOOKING STATEMENTS Headquartered: Houston, Texas ( NYSE : ) Certain statements in this presentation regarding future expectations and plans for future activities may be regarded as forward-looking statements within the meaning of the Private Securities Litigation Reform Act of They are subject to various risks, such as financial market conditions, operating hazards, drilling risks and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas, as well as other risks discussed in detail in the Company s Annual Report on Form 10-K and other filings with the Securities and Exchange Commission. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Proved reserves described in this presentation meet definitions and guidelines of the U.S. Securities and Exchange Commission (SEC) for such reserves. We have also included in this presentation internally generated estimates of non-proved or 3P (proved+probable+possible) reserves, resources and well locations, or potential non-proved or 3P reserves, resources and well locations. These estimates are inherently more speculative than our estimates of proved reserves and there is no assurance that we will drill these wells or recover these hydrocarbon quantities. Our probable and possible resource potential included herein is based on internal estimates and our ultimate recovery will be dependent upon numerous factors including actual geological conditions, the impact of future oil and gas pricing and exploration costs, and our future drilling decisions and budgets based upon our future evaluation of risk, returns and the availability of capital. The SEC has generally permitted oil and gas companies in their filings with the SEC to disclose only reserves meeting SEC definitions and guidelines and only separately by reserve category. 2

3 COMPANY PROFILE Proved Reserves PV10 Growth ($MM) 1 $148 $147 $1 $343 $19 Oil & NGL $294 $158 $27 Gas $99 $332 $373 $68 $ $148 $148 $362 $452 $359 $472 TMS Haynesville Shale Eagle Ford Shale $362 $15 $347 $452 $158 $294 $359 $322 $30 $7 $472 $291 $99 $82 $651 $651 $190 $68 $393 Large core acreage position with 562,500 gross (392,930 net) acres in Texas, Louisiana and Mississippi, with over 7.1 Tcfe of resource potential: 325,000+ net acres in the Tuscaloosa Marine Shale (150,000 in delineated core) Approximately 30,000 net acres in the oil window of the Eagle Ford Shale in La Salle and Frio counties Texas 36,000 net acres prospective in the Haynesville Shale trend (14,300 net acres in the core of North Louisiana and 21,700 net acres in the Angelina River Trend of Shelby Trough) At SEC pricing: YE09: Gas $3.87/MMbtu, Oil $57.65/Bbl; YE10: Gas $4.38/MMbtu, Oil $75.96/Bbl; YE11: Gas $4.12/MMbtu, Oil $92.71/Bbl; YE12: Gas $2.78/MMbtu, Oil $91.21/Bbl YE13: Gas $3.67/MMbtu, Oil $96.94/Bbl; YE14: Gas $4.35/MMbtu, Oil $94.99/Bbl 3

4 CORE PROPERTIES Acreage: 562,550 gross (392,900 net) HAYNESVILLE SHALE - CORE Gross (Net) Acres: 31,150 (14,300) Proved Reserves (YE'14): 83 Bcfe Probable/Possible Potential (1) : 566 Bcfe Objective: Haynesville Shale (Core) HAYNESVILLE / BOSSIER SHALE ANGELINA RIVER TREND ( ART ) Mississippi Gross (Net) Acres : 28,000 (21,700) Proved Reserves (YE'14): 11 Bcfe Probable/Possible Potential (1) : 1,656 Bcfe Objective: Haynesville & Bossier Shale Texas TUSCALOOSA MARINE SHALE: Louisiana Gross (Net) Acres: 459,000 (327,000) Proved Reserves (YE 14): 19 MMBoe Risked Resource Potential (1) : 693 MMBoe Objectives: Tuscaloosa Marine Shale EAGLE FORD SHALE: Gross (Net) Acres: 44,400 (30,000) Proved Reserves (YE 14): 10 MMBoe Risked Resource Potential (1) : 75 MMBoe Objectives: Eagle Ford Shale, Pearsall Shale & Buda Lime (1) Internal estimates as of 12/31/14. Actual reserves dependent upon pricing and cost assumptions. See assumptions on the Drilling Inventory slide. 4

5 TUSCALOOSA MARINE SHALE Emerging shale oil play covering approximately 2.5 million acres Low cost basis on 300,000+ net acres Vintage wells define oil saturation and rock quality Depths: 10,500 14,500 TVD Thickness High quality crude (38 45 deg. API) 92 98% oil, High BTU gas 5

6 TUSCALOOSA MARINE SHALE T. Lewis 7-38H-1 (Completing) Kinchen 58H-1 (Completing) B-Nez 43H-1 (Completing) B-Nez 43H-2 (Completing) W Alford 10H1 (Completing) Legend TMS Oil Shows (Vertical) Drilled/Completed TMS Wells Permitted TMS Wells Legacy Acreage TMS Acquisition Acreage Wells Drilling Wells Completing 1. Non-Operated (0% WI), IP: 1,915 Boe/d (24-hr), ~7,000 ft, 19 stgs 2. Non-Operated (0% WI), IP: 1,600 Boe/d (24-hr), ~9,800 ft, 29 stgs 3. ECA Mathis 29-17H-1 (0% WI), IP: 1,570 Boe/d (24-hr), ~9,100 ft, 26 stgs 4. ECA Lyons 35H-2 (0% WI), IP: 1,535 Boe/d (24-hr), ~5,200 ft, 19 stgs 5. ECA Lewis 7-18H-1 (17% WI), IP: 1,500 Boe/d (24-hr), ~8,100 ft, 29 stgs 6. C.H. Lewis 30-19H-1 (81.4% WI), IP: 1,450 Boe/d (24-hr), ~6,600 ft, 26 stgs 7. Verberne 5H-1 (66.7% WI), IP: 1,375 Boe/d (24-hr), ~6,600 ft, 21 stgs 8. 6 Spears 31-6H-1 (77.0% WI), IP: 1,360 Boe/d (24-hr), ~6,200 ft, 23 stgs Painter 5H1 (Completing) Kent 41H-1 (Completing) 9. Crosby 12H-1 (50% WI), IP: 1,300 Boe/d (24-hr), ~6,700 ft, 24 stgs 10. ECA Mathis 29-32H-1 (0% WI), IP: 1,300 Boe/d (24-hr), ~6,400 ft, 17 stgs 11. Blades 33H-1 (66.7% WI), IP: 1,270 Boe/d (24-hr), ~5,100 ft, 20 stgs 12. Denkmann 33-28H-2 (75% WI), IP: 1,250 Boe/d (24-hr), ~6,000 ft, 22 stgs 13. Williams 46H-1 (68.2% WI), IP: 1,240 Boe/d (24-hr), ~6,400 ft, 20 stgs 14. CMR 24-13H-1 (97% WI), IP: 1,215 Boe/d (24-hr), ~6,500 ft, 24 stgs 15. CMR 31-22H-1 (90% WI), IP: 1,140 Boe/d (24-hr), ~6,700 ft, 24 stgs 16. SN St. Davis 1H (0% WI), IP: 1,140 Boe/d (24-hr.), ~5,600 ft, 25 stgs

7 TMS OPTIMIZED WELLS (30) Well Control & Structure Map 500 Contour Currently delineated core (: 150,000 net acres) Crosby 12H-1 CMR Foster Creek 8H -2 CMR 8-5H-1 C.H. Lewis 30-19H-1 Nunnery 12-1H-1 WILKINSON Area #1 Area #2 PIKE WALTHALL CMR Foster Creek 24-13H-1 AMITE Blades 33H-1 Area #4 Area #3 WASHINGTON SLC, Inc. 81H-1 WEST FELICIANA EAST FELICIANA Williams 46H-1 ST. HELENA TANGIPAHOA Verberne 5H-1 CMR Foster Creek 31-22H-1 Beech Grove 94H-1 Denkmann 33-28H-2 Spears 31-6H-1 Red well markings represent approximately 1,350 vertical penetrations through the TMS 90% of acreage at -14,000 TVD or shallower, where most wells have been completed to date Green dots represent wells waiting on completion Nunnery is the most up-dip (-10,825 Subsea TVD; 17,550 MD; 5,450 horizontal) SLC is the deepest optimally completed well drilled to date (-13,809 SS TVD; 21,450 MD; 7,000 horizontal) Active Rigs 7

8 OPTIMIZED TMS WELLS (30) Optimized Criteria: Lower TMS landing target 5,000 + lateral length >450,000 lbs. proppant per stage (>1,500 lbs. per foot) Optimum hybrid slick water frac design Optimized TMS Wells: Crosby 12 H1 CMR 8-5 H1 Blades 33 H1 CH Lewis 30 H1 Spears 31-6 H1 Nunnery 12 H1 Beech Grove 94 SLC 81 H1 Denkmann H2 CMR FC H1 CMR FC H1 Verberne 5 H1 Williams 46 H1 CMR FC 8 H2 ECA Mathis H1 ECA Lewis 7-18 H1 Non-Operated #1 Non-Operated #2 Non-Operated #3 Non-Operated #4 Non-Operated #5 Non-Operated #6 Non-Operated #7 Non-Operated #8 Non-Operated #9 Non-Operated #10 Non-Operated #11 Non-Operated #12 Non-Operated #13 Non-Operated #14 8

9 OPTIMIZED WELL PERFORMANCE Area #1 (Core) 9

10 OPTIMIZED WELL PERFORMANCE Area #2 (Core) 10

11 OPTIMIZED WELL PERFORMANCE Area #3 (Core) 11

12 OPTIMIZED WELL PERFORMANCE Area #4 (Non-Core) 12

13 TMS TYPE CURVE (600 & 800 MBOE) Optimized Wells (30) 13

14 TMS OPTIMIZED COMPOSITE WELL DECLINE CURVE 30 Wells 82.6% NRI, $10.0MM, $65/bbl Type Curves Gross Reserves 700 Mboe 600 Mboe Net Reserves 578 Mboe 496 Mboe F&D Cost ($/BOE) $17.30 $20.16 IRR 32% 22% NPV ($MM) $5.38 $3.31 Core locations 1,500-2, % NRI, $10.0MM, $75/bbl Type Curves Gross Reserves 700 Mboe 600 Mboe Net Reserves 578 Mboe 496 Mboe F&D Cost ($/BOE) $17.30 $20.16 IRR 48% 33% NPV ($MM) $7.82 $5.48 Core locations 1,500-2,000 Note: with +$5/bbl uplift 14

15 TMS AVERAGE DRILL TIME BY QUARTER 15

16 COST BREAKDOWN (USD in millions) ,000 Single-Well Pad ,000 Single-Well Pad (High-Proppant) ,000 Two-Well Pad (High-Proppant) Drilling 40 Days 24 Days 24 Days Intangible $4.7 $3.6 $3.2 Tangible Run Casing Total Drill $7.0 $5.6 $5.2 Completion Intangible $5.7 $4.1 $3.8 Tangible Total Completion $6.0 $4.4 $4.1 Well Total $13.0 $10.0 $9.3 16

17 TMS WELL ECONOMIC SUMMARY Well Cost: $10.0 MM Lateral Length: 6,000 Frac Stages: 20 Royalty Burden: 17.4% Severance Tax: Reserves (Gross): Reserves (Net): 0% until Payout 12.5% after Payout 700 MBOE 578 MBOE Current single-well pad AFE is approximately $10.0 MM. Additional cost savings from twowell pad drilling: rig MOB, location, mud system, zipper / simultaneous fracs, and sharing of production equipment and facilities. F&D Cost ($/BOE): $17.30 IRR: 48% NPV ($MM): $7.82 MM Note: Economics assumes $75/Bbl NYMEX crude oil pricing. 17

18 EUR TMS WELL ECONOMICS $10.0 MM Capex Breakeven Economics $10 MM 600 MBoe $50/Bbl 700 MBoe $44/Bbl 800 MBoe $37/Bbl Note: Internally estimated type curve. IRR assumes an 82.6% NRI, 2-year tax abatement and a premium to NYMEX of $5/Bbl. Breakeven economics assumes WTI oil price to generate a 10% internal rate of return. 18

19 NYSE: 19