Abraxas Petroleum 8K Regulation FD Disclosure | AXAS 28 May 13

SunTrust “Play-by-Play” Oil and Gas Conference May 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) ……………………. $229 mm Bank debt net of cash(1)…… $119 mm PV-10(4)…………………………… $312.1 mm Fully Diluted as of 3/31/13 As of 5/24/13 Net proved reserves as of December 31, 2012 adjusted for recent asset sales in TX, OK, ND and LA.. 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 and annualized daily net production for the quarter ended March 31, 2013 EV/BOE(1,2,3)…………………… $12.06 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. 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 (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.

* II. Western Bakken Data Mine Project

* Our Goal: identify best practices through inductive, results-oriented data mining Western Bakken Data Mine Project

* Learning opportunities: - NDIC database - Non-operated participation Western Bakken Data Mine Project

* The Variables: why induction is so important Western Bakken Data Mine Project

* Steering effectiveness Lateral length Number of stages Size of stages Exit method Proppant/fluid selection Operational execution Geologic variation Western Bakken Data Mine Project

* ca 2000 ELM COULEE ELKHORN RANCH NESSON ANTICLINE Western Bakken Data Mine Project

* ca 2004 ELM COULEE ELKHORN RANCH NESSON ANTICLINE Western Bakken Data Mine Project

* Today Western Bakken Data Mine Project

* 2005 Western Bakken Data Mine Project

* 2006 Western Bakken Data Mine Project

* 2007 Western Bakken Data Mine Project

* 2008 Western Bakken Data Mine Project

* 2009 Western Bakken Data Mine Project

* 2010 Western Bakken Data Mine Project

* 2011 Western Bakken Data Mine Project

* 2012 Western Bakken Data Mine Project

* Study Area Western Bakken Data Mine Project

* 4927 total wells 4223 in western Bakken 3076 in study area 634 wells with comprehensive frac data Western Bakken Data Mine Project

* Western Bakken Data Mine Project

* Measure of a Well: best month as a quality proxy Western Bakken Data Mine Project

* Western Bakken Data Mine Project

* > 20000 bopm Western Bakken Data Mine Project

* best month contour CI = 2500 bopm 0 to 30,000 max Best Month Contour Western Bakken Data Mine Project

* ALL WELLS > 2005 IP = 11,549 BOPM di = 98.0% b = 1.25 EUR = 281 MBO Western Bakken Data Mine Project

* ALL WELLS > 2009 IP = 13,488 BOPM di = 99.0% b = 1.60 EUR = 409 MBO Western Bakken Data Mine Project

* Conclusion: results have improved with time Western Bakken Data Mine Project

* Western Bakken Data Mine Project

* y = 1.224x + 1112 Western Bakken Data Mine Project

* Conclusion: results improve with lateral length Western Bakken Data Mine Project

* Western Bakken Data Mine Project

* y = 253x +7779 Western Bakken Data Mine Project

* Western Bakken Data Mine Project

* y = .002x +8880 Western Bakken Data Mine Project

* Conclusion: mass and stage number also matter Western Bakken Data Mine Project

* Completion Strategy Comparison exit stgs best mo. di b eur 1 p&p 34 19840 99.9 1.9 528 2 slvs 30 16480 99.8 2.0 538 3 p&p 24 12494 99.0 1.5 370 4 p&p 18 8854 94.8 1.5 323 Western Bakken Data Mine Project

* Conclusion: number of stages seems to matter more than exit method Western Bakken Data Mine Project

* avg = 13488 bopm Western Bakken Data Mine Project

* Average Well Economics case cwc ip eur ror po pv10 mm$ bopm mboe % yrs mm$ avg 9.5 13488 465 17.8 4.3 2.34 *all eco @ nymex $95 / $3.50 adjusted for typical differentials Western Bakken Data Mine Project

* Economic Strategy Comparison case cwc ip eur ror po pv10 mm$ bopm mboe % yrs mm$ 1 10.0 19840 621 25.5 3.4 4.98 2 8.0 12494 439 25.0 3.2 3.34 Western Bakken Data Mine Project

* Conclusion: the high and low-cost completion models seem to yield similar returns Western Bakken Data Mine Project

* Abraxas Take-Aways: Drill the longest lateral possible Save money on exit method Don’t scrimp on number of stages Don’t scrimp on prop mass Western Bakken Data Mine Project

* Appendix

* 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. 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

* 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 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.

* Non-Op Bakken Divestiture Plan On February 20, 2013, Abraxas announced that it had retained E-Spectrum Advisors (an affiliate of Energy Spectrum Advisors Inc.) to market its non-operated Bakken and Three Forks assets in North Dakota and Montana Asset Details: 13,618 net acres in Billings, Burke, Divide, Dunn, McKenzie, Stark and Williams Counties, ND and Richland, Roosevelt and Sheridan Counties, MT 99% of acreage is held-by-production ~343 boepd (March) Diverse and experienced operator base including: Oasis Petroleum, Continental, ExxonMobil / XTO / Denbury, Whiting, Fidelity E&P, Hess, Statoil / Brigham, Citation, Petro-Hunt and others. If the Company is successful in achieving an acceptable price for these assets, the proceeds will be used to pay down the Company’s revolver and redeployed into its core operated Bakken and Eagle Ford assets Overview Asset Map

* 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 $10.5(1) Producing Ravin 26-35 3H Middle Bakken 10,000 26 627 $10.4(1) Producing Lillibridge 4H Three Forks 8,472 28 NA NA TD/Cased Lillibridge 3H Middle Bakken 10,000 28 NA NA TD/Cased Lillibridge 2H Three Forks 9,529 28 NA NA TD/Cased Lillibridge 1H Middle Bakken 10,000 28 NA NA TD/Cased Focused on successful execution of long lateral horizontals: Reducing costs with pad operations Maintain flexibility & consistency with Company owned drill rig and in-house team Maintain lateral in the target zone to ensure effective depletion Plug and perf a large number of stages to maximize drainage Flow back prudently to avoid damaging the formation Feedback loop to constantly learn and improve The Lillibridge Completion in the North Fork Area Bakken / Three Forks Focused on Execution Does not deduct settlement with third party service provider

* 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 NA Completing Corvette A 1H Eagle Ford 5,000 19 NA NA Waiting on Completion Camaro B 4H 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

* 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

Abraxas Petroleum (AXAS) 8-KRegulation FD Disclosure