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8-K - FORM 8-K - ABRAXAS PETROLEUM CORPaxasjunepresentation8k.htm
TPH Hotter ‘N Hell Energy Conference June 2013 Exhibit 99.1
 
 
 

 
* The information presented herein may contain predictions, estimates and other forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved. Important factors that could cause actual results to differ materially from those included in the forward-looking statements include the timing and extent of changes in commodity prices for oil and gas, the need to develop and replace reserves, environmental risks, competition, government regulation and the ability of the Company to meet its stated business goals. Forward-Looking Statements
 
 
 

 
* I. Abraxas Petroleum Overview
 
 
 

 
* Headquarters...................... San Antonio Employees........................... 105 Shares outstanding(1)……..... 93.3 mm Market cap(2) ………………….. $202 mm Bank debt net of cash(1)…… $119 mm PV-10(4)……………………………. $312.1 mm Fully Diluted as of 3/31/13 As of 6/14/13 Net proved reserves as of December 31, 2012 adjusted for recent asset sales in TX, OK, ND and LA.. Does not account for recent Bakken non-op sale. Uses 12/31/12 SEC Pricing of $95.14/bbl oil and $2.86/mcf gas Net proved reserves as of December 31, 2012 adjusted for recent asset sales in TX, LA, OK, ND. Does not account for recent Bakken non-op sale. Annualized daily net production for the quarter ended March 31, 2013 EV/BOE(1,2,3)…………………… $11.16 Proved Reserves(3).………….. 29.8 mmboe % Oil/Liquids………….. ~66% % Proved developed… ~48% Production(1).…………………… 4,216 boepd R/P Ratio(4)……………………… 19.4x 2013E CAPEX…………………… $70mm NASDAQ: AXAS Corporate Profile
 
 
 

 
* Exposure to "core" acreage in U.S. oil resource plays Significant, low-cost exposure to other emerging NAM oil resource plays Premier Position Value + Growth Low decline legacy production provides solid foundation “Manufacturing” model in repeatable resource plays leads to visible growth Proven Operator Deep technical and geological / geophysical staff Company owned rig in Bakken + pad drilling = efficient, low cost operator Oil Weighted 66% crude oil and liquids weighted by reserves(1) Nearly 100% of 2013E capital directed towards growing production from oil resource plays On reserve basis as of 12/31/12 adjusted for recent asset sales in TX, OK, ND and LA. Does not account for recent Bakken non-op sale. Experienced Leadership Senior management with 32 average years of industry experience Highly qualified directors with significant energy industry and board experience Abraxas Highlights
 
 
 

 
* Proved Reserves(1) – 29.8 mmboe Production(2) – 4,216 boepd Net proved reserves as of December 31, 2012 adjusted for recent asset sales in TX, OK, ND and LA. Does not account for recent Bakken non-op sale. Daily net production for the quarter ended March 31, 2013 Reserve Mix(1) Revenue By Production Stream Reserve / Production Summary High-quality, Long-Lived, Oil Weighted Assets
 
 
 

 
* Includes AXAS’ share of Blue Eagle’s production (50% in Q1 and Q2 2011, 41% in Q3 2011 and 35% in Q4 2011, Q1 2012 and Q2 2012) (Boepd) Oil/NGL % 34% 35% 36% 39% 43% 44% 48% 48% 52% 53% 53% 54% 58% Production Net to AXAS(1) 81% Liquids Growth Since 1Q10 Refocusing on Oil and Liquids
 
 
 

 
* Proved Reserves (mmboe)(1): 29.8 Proved Developed(1): 48% Liquids(1): 66% Abraxas Petroleum Corporation Alberta, Canada Williston: Bakken / Three Forks Powder River Basin: Niobrara, Turner Midland/Eastern Shelf: Emerging Cline, Wolfcamp Eagle Ford Shale CBP: Conventional Delaware Basin: Montoya/Devonian/Miss Gas, Shallow Oil, Emerging Hz. Oil Rocky Mountain Gulf Coast Permian Basin Canada Pekisko Eastern Shale Basin: Duvernay High Quality Assets Core NonCore WolfBone Uinta / Wind River / Green River Dry Gas Net proved reserves as of December 31, 2012 adjusted for recent asset sales in TX, OK, ND and LA. Does not account for recent Bakken non-op sale.
 
 
 

 
* II. Strategic Plan
 
 
 

 
* Strategic Plan Excluding building mortgage and rig loan which are secured by the building and rig, respectively. EBITDA definition per bank loan agreement (excludes Rig EBITDA)
 
 
 

 
* 9/12 Strategic Plan - Successful Execution Sales proceeds inclusive of an estimated $8.1 million of assumed CAPEX associated with AFEs on 25 wells in Abraxas’ non-operated Bakken sale As of 12/31/2011 As of 3/31/13 Excluding building mortgage and rig loan which are secured by the building and rig, respectively. EBITDA definition per bank loan agreement (excludes Rig EBITDA) Proved reserves as of December 31, 2012 excluding recent asset sales in LA, OK, ND and TX. Does not account for recent Bakken non-op sale.
 
 
 

 
* III. Asset Base Overview
 
 
 

 
* Bakken / Three Forks Positioned in a Core Area (NorthFork) Operator Abraxas Burlington Continental Hess Kodiak Newfield Petro-Hunt QEP Slawson SM XTO Other SM Nelson 15-11H 20 Stages 24-hr IP rate: 994 bbl/d, 1,417 mcf/d XTO Lund 26-18SH 22 Stages 24-hr IP rate: 1,252 bbl/d, 2,300 mcf/d Abraxas Stenehjem 27-34-1H 17 Stages 24-hr IP rate: 862 bbl/d, 1,365 mcf/d Abraxas Jore Federal 2-11-3H 35 Stages 24-hr IP rate: 761 bbl/d, 1,759 mcf/d XTO Badlands Federal 21X-13 24 Stages 24-hr IP rate: 1,029 bbl/d, 1,458 mcf/d XTO Mariana Trust 12X-20H Recently Completed Results Pending Abraxas Ravin 26-35-1H 23 Stages 24-hr IP rate: 1,008 bbl/d, 1,342 mcf/d Burlington Morgan 21-28MBH-2NH 13 Stages 24-hr IP rate: 2,004 bbl/d, 3,328 mcf/d Burlington Kirkland 21-28MBH 12 Stages 24-hr IP rate: 2,325 bbl/d, 4,411 mcf/d ___________________________________ Source: HPDI. Horizontal wells drilled since 1/2010 XTO Lundin 11-4SH 16 Stages 24-hr IP rate: 878 bbl/d, 1,535 mcf/d
 
 
 

 
* Bakken / Three Forks Positioned in a Core Area (Harding) Operator Abraxas Brigham Continental Murex Petro-Hunt Whiting XTO Zavanna Zenergy Other Zenergy Cayko 22-27H 30 Stages 24-hr IP Rate: 923 bopd, 767 mcfpd Zenergy Helm 19-30HTF 30 Stages 24-hr IP Rate: 758 bopd, 766 mcfpd Whiting Miller 34-8-1H 12 stages 24-hr IP Rate: 1,304 bopd, 1,023 mcfpd Whiting Langwald 31-17-1H 10 stages 24-hr IP Rate: 834 bopd, 637 mcfpd Whiting Amber Elizabeth 9-4H Proposed 30 stages 24-hr IP Rate: 1,168 bopd, 882 mcfpd Brigham (Statoil) Sundheim 26-35 2H Recently Completed Results Pending Brigham (Statoil) Sundheim 26-35-1H Recently Completed Results Pending ___________________________________ Source: HPDI. Horizontal wells drilled since 1/2010 Whiting Evy June 18-19H Proposed 30 stages 24-hr IP Rate: 612 bopd, 340 mcfpd Zenergy Knels 20-29H 30 Stages 24-hr IP Rate: 671 bopd, 446 mcfpd Zenergy Stepan 16-9H 30 Stages 24-hr IP: 1,309 bopd, 1,029 mcfpd Zenergy Stepan 21-28H 27 Stages 24-hr IP Rate: 741 bopd, 524 mcfpd
 
 
 

 
             
             
             
             
             
             
             
             
             
             
             
             
             
             
* Well Objective Lat. Length Stages 30-day IP (boepd) Well Cost ($mm) Status Ravin 26-35 1H Three Forks 10,000 23 391 $13.0 Producing Stenehjem 27-34 1H Middle Bakken 6,000 17 688 $11.5 Producing Jore Federal 2-11 3H Three Forks 10,000 35 510 $8.7 Producing Ravin 26-35 2H Middle Bakken 10,000 16 421 $10.0 Producing Ravin 26-35 3H Middle Bakken 10,000 26 627 $9.9 Producing Lillibridge 4H Three Forks 8,472 26 NA NA Prep Frac Lillibridge 3H Middle Bakken 10,000 33 NA NA Prep Frac Lillibridge 2H Three Forks 9,529 30 NA NA Prep Frac Lillibridge 1H Middle Bakken 10,000 33 NA NA Prep Frac Lillibridge 8H Three Forks 10,000 NA NA NA Surface TD/Cased Lillibridge 7H Middle Bakken 10,000 NA NA NA Surface TD/Cased Lillibridge 6H Three Forks 10,000 NA NA NA Surface TD/Cased Lillibridge 5H Middle Bakken 10,000 NA NA NA Surface TD/Cased; Drilling Intermediate Bakken / Three Forks Focused on Execution
 
 
 

 
 
   
   
   
 
   
   
   
   
* Bakken / Three Forks Outperforming Type Curve (NorthFork) Single Well Economics Single Well Economics EUR (Mboe) ~462 Commodity Split 80% oil 8% NGLs 11% gas D&C Cost $8.5mm Type Curve Parameters Type Curve Parameters di (%) 99 b 1.5 dm (%) 7 GOR (scf/bbl) 1,150
 
 
 

 
* Eagle Ford Positioned in a Core Area (WyCross) Operator Abraxas Aurora Carrizo Chesapeake Comstock EOG Murphy Swift Talisman Other EOG San Miguel A Unit 4H 24-hr IP rate: 1,580 bopd, 665 mcfpd Carrizo J Rayes 21H 22 Stages 24-hr IP rate: 879 bopd, 276 mcfpd EOG Koenig 4H 24-hr IP rate: 1,470 bopd, 692 mcfpd EOG San Miguel B Unit 4H 5,845 ft Lateral 24-hr IP: 1,213 bopd, 495 mcfpd EOG Swaim 5H 24-hr IP rate: 1,080 bopd, 764 mfcpd Comstock Cutter Creek 2H 16 Stages 24-hr IP rate: 471 bopd, 422 mcfpd Comstock Cutter Creek A 1H 15 Stages 24-hr IP rate: 696 bopd, 413 mcfpd Abraxas Corvette C 1H 19 Stages 24-hr IP rate: 1,227bopd, 488 mcfpd Abraxas Cobra 1H 18 Stages 24-hr IP: 1,050 bopd, 696 mcfpd Abraxas Mustang 3H 19 Stages 24-hr IP: 1,359 bopd, 589 mcfpd Chesapeake Peeler MCM E 3H 6,238 ft Lateral 24-hr IP rate: 857 bopd, 164 mcfpd Chesapeake Peeler MCM D 4H 6,217 ft Lateral 24-hr IP rate: 694 bopd, 924 mcfpd ___________________________________ Source: HPDI. Horizontal wells drilled since 1/2010
 
 
 

 
             
             
             
             
             
             
             
             
             
             
             
             
   
   
   
* Eagle Ford Outperforming Type Curve (WyCross) Well Objective Lat. Length Stages 30-day IP (boepd) Well Cost ($mm) Status Cobra 1H Eagle Ford 5,000 18 957 $10.1 Producing Cobra B 1H Eagle Ford 5,000 19 592 $6.6 Producing Mustang 1H Eagle Ford 5,000 19 1,152 $8.3 Producing Corvette C 1H Eagle Ford 5,000 20 867 $6.1 Producing Gran Torino A 1H Eagle Ford 5,000 21 790 $7.0 Producing Mustang 3H Eagle Ford 5,000 18 1,184 $6.2 Producing Mustang 2H Eagle Ford 5,000 19 511 $6.3 Producing Sting Ray A 1H Eagle Ford 7,500 29 NA $8.9 Producing Corvette A 1H Eagle Ford 5,000 19 NA $5.8 Producing Camaro B 4H Eagle Ford 5,000 19 NA NA TD Cased; 40 Acre Pilot Camaro B 3H Eagle Ford 5,000 19 NA NA Drilling; 40 Acre Pilot Drilled & Completed Scheduled Locations Incremental Locations Upcoming 40 Acre Pilot
 
 
 

 
 
   
   
   
 
   
   
   
   
* Eagle Ford Outperforming Type Curve Single Well Economics Single Well Economics EUR (Mboe) ~575 Commodity Split 70% oil 11% NGLs 20% gas D&C Cost $7.0mm Type Curve Parameters Type Curve Parameters di (%) 99.11 b 1.3 dm (%) 7 GOR (scf/bbl) 1,000
 
 
 

 
* Additional Development Areas
 
 
 

 
* Appendix
 
 
 

 
* Converse / Niobrara Counties, Wyoming Gross / Net Acres: 29,170 / 21,540 Primarily in Converse & Niobrara Counties ~4,300 net acres in Campbell County ~90% held by production Historical Activity: 13 wells (2000 – 2011) 8 horizontal / 5 vertical Recent Activity: Hedgehog State 16-2H (Crossbow) Cum production (15 mos): 137.1 MBoe 31% Oil / NGLs Brooks Draw: Sage Grouse 3H: (Cum Oil 25 MBbl / 50 MBbl EUR) Prairie Falcon 3H (Niobrara) Recent Industry Activity: 74 Permits 8 Completions Porcupine Field: Hedgehog State 16-2H (Turner) PRB – Stacked Pay Opportunities
 
 
 

 
* Spires Ranch (Nolan County) 5,640 gross/net acres; 920 HBPd Monitoring industry activity Geologic evaluation Logged shales through Spires 89 1H Millican Reef (Coke County) 6,725 gross/net acres Monitoring industry activity Geologic evaluation Permian Basin – Emerging Hz
 
 
 

 
* EOG Strikes Oil in Duvernay's East Shale Basin “New public data for EOG’s Duvernay horizontal at 1-20-38-28W4 showed a peak calendar-day rate to date of 239 boe/d for December. Oil comprised 88% of the wellhead production stream…We believe there is a possibility EOG is restricting rates or testing the well, meaning it could be producing the well intermittently through the months. The reported rates are in the ballpark of our Eagle Ford West oil type curve peak rate of ~300 boe/d. Under Crown royalties, the Eagle Ford West type curve results in a break-even price of $82/boe and a per-well NPV of $1 million, assuming a $9 million well cost.” -- ITG, February 7, 2013 Alberta, Canada: Eastern Shale Basin Recently Drilled Neighboring Well Duvernay: Net Acres: 42,880 (100% WI) Crown: 32 Sections; five year leases Farm-out/option: 35 Sections; three year term Represents a continuous, self sourced resource contained in a shaley organic rich low permeability reservoir Shale assessment and productivity expectations developed based on a review of analogues (i.e. Eagle Ford, Kaybob, Pembina/ Willesden Green) All critical shale parameters point to the Duvernay being an excellent source and reservoir rock Available rock and completion data point to Canaxas lands containing volatile oil hydrocarbons in place Planned Activity: Drill vertical pressure test Canada – Duvernay
 
 
 

 
* Canada – Duvernay
 
 
 

 
* Edwards (South Texas) PDP: 10.3 bcfe (net) Nordheim 2H: 7.0 bcfe gross Keuster 1H: 10.5 bcfe gross Previous risked offsetting PUD locations: 27.9 bcfe (net) 11 gross / 7 net locations dropped to PRUD (SEC 5 year rule) 7 gross / 5 net locations drilled / completed, yet to be frac’d: unbooked Edwards economics New drill: $7.0 million well / 4.0 bcfe EUR / F&D $1.73/mcfe 20% ROR at $4.30/mcfe realized price Refrac: $0.7 million well / 0.5 bcfe EUR / F&D $1.40/mcfe 20% ROR at $1.98/mcfe realized price Montoya / Devonian (Delaware Basin, West Texas) PDP 28.0 bcfe (net) Caprito 98 98 01U Devonian: 39.0 bcfe gross Howe GU 5 1 Devonian: 31.7 bcfe gross Previous risked offsetting PUD locations: 29.7 bcfe (net) 12 gross/ 6 net locations dropped to PRUD (SEC 5 year rule) Montoya economics $5.0 million well / 6.6 bcfe EUR / F&D $.75/mcfe 20% ROR at $3.16/mcfe realized price Devonian economics $5.8 million well / 7.6 bcfe EUR / F&D $0.76/mcfe 20% ROR at $2.51/mcfe realized price Other Eagle Ford Shale, Yoakum: 1,908 net acres / ~24 net locations, unbooked PRB, Turner (~50% gas): 2 gross (1.7 net) PUD / 50 gross (13 net) PRUD locations, 40.6 bcfe (net) Delaware Basin, Hudgins Ranch: 3 gross / 2.6 net PSUD locations, 9.1 bcfe (net) Delaware Basin, Nine Mile Draw: 40 gross / 31 net PSUD locations, 18.0 bcfe (net) Wind River, Cow Hollow Field: 5 gross / .06 net PRUD locations, 0.7 bcfe (net) Williston Basin, Red River: 1 gross / .8 net PRUD location, 2.1 bcfe (net) Uinta, Chapita Wells, unbooked Net of purchase price adjustments PV10 calculated using strip pricing as of 5/1/12 = $2.29 2012 Ward County Acquisition Acquisition of Partners’ Interests in West Texas Purchase Price $6.7mm(1) PDP PV -15 $6.7mm(2) Production 1,440 mcfepd Reserves 7.613 bcfe Production $4,650/mcfe/day Reserves: $.88/mcfe Abraxas’ “Hidden” Gas Portfolio
 
 
 

 
* NASDAQ: AXAS