8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

June 21, 2016

Date of Report (Date of earliest event reported)

ABRAXAS PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Nevada	1-16071	74-2584033
(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification Number)

18803 Meisner Drive

San Antonio, Texas 78258

(210) 490-4788

(Address of principal executive offices and Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e- 4(c))

Item 7.01 Regulation FD Disclosure

Abraxas meets with analysts and investors on a regular basis.  The attached June 2016 Corporate Update, attached as Exhibit 99.1 will be used in these discussions..

The information in this Report (including Exhibit 99.1) is furnished pursuant to Item 7.01 and shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of the Section. The information in this Report will not be deemed an admission as to the materiality of any information required to be disclosed solely to satisfy the requirements of Regulation FD.

Item 9.01 Financial Statements and Exhibits.

(d)    Exhibits.

99.1 Presentation

2

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

ABRAXAS PETROLEUM CORPORATION

By: /s/ Geoffrey R. King    

Geoffrey R. King

Vice President, Chief Financial Officer

Dated: June 21, 2016

3

EX-99.1

Abraxas Petroleum Corporate Update June 2016 Raven Rig #1; McKenzie County, ND Exhibit 99.1

2 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, availability of capital, 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

3 I. Abraxas Petroleum Overview

4 Headquarters.......................... San Antonio Employees(1)............................ 89 Shares outstanding(2)……......... 135.1 mm Market cap(4) …………………….... $152.6 mm Net debt(3)………………………….. $98.0 mm 2016E CAPEX………………………. $40 mm (1) As of May 25, 2016. Does not include nine employees associated with the Company’s wholly owned subsidiary, Raven Drilling. (2) Shares outstanding as of May 25, 2016. (3) Total debt including RBL facility, rig loan and building mortgage less cash as of May 25, 2016. (4) Share price as of May 31, 2016. (5) Enterprise value includes working capital deficit (excluding current hedging assets and liabilities) as of May 25, 2016, but does not include building mortgage or rig loan. Includes RBL facility, rig loan and building mortgage less cash as of May 25, 2016. (6) Average production for the quarter ended March 31, 2016. (7) Calculation using average production for the quarter ended March 31, 2016 annualized and net proved reserves as of December 31, 2015. (8) Proved reserves as of December 31, 2015. Uses SEC YE2014 average pricing of $50.12/bbl and $2.63/mcf. See appendix for reconciliation of PV-10 to standardized measure. (9) Net book value of other assets as of March 31, 2016. EV/BOE(3,4,5)………………………... $5.91 Proved Reserves(8).…………..... 43.2 mmboe PV-10(8)……………………………….. $197.3 mm NBV Non-Oil & Gas Assets(9).. $26.9 mm Production(6).……………………… 5,916 boepd R/P Ratio(7)…………………………. 20.0x NASDAQ: AXAS Corporate Profile

5 Williston: Bakken / Three Forks Powder River Basin: Turner Eastern Shelf: Conventional & Emerging Hz Oil Eagle Ford Shale / Austin Chalk Delaware Basin: Bone Spring & Wolfcamp Rocky Mountain Gulf Coast Permian Basin Legend Proved Reserves (mmboe)(1): 43.2  Proved Developed(1): 32%  Oil(1): 56%  Current Prod (boe/d) (2): 5,916 Abraxas Petroleum Corporation Core Regions (1) Net proved reserves as of December 31, 2015. (2) Average production for quarter end March 31, 2016 2016 Capex Focus Areas

6 Key Investment Highlights  5,227 net HBP acres prospective for the Wolfcamp A & Bone Spring intervals  Recent Wolfcamp A & Bone Spring offset results demonstrate +1,500 boe/d 24-hour average rates  Plan to drill two 5,000 ft. Wolfcamp A laterals to test acreage in 2016 with first well to spud in July  Currently drilling first 5,700 ft. lateral Austin Chalk well test Emerging Delaware Basin and Austin Chalk Exposure  Total bank debt of $93 million (2) represents the only meaningful leverage (1, 2) of the company and is funded under recently re-determined $130 million revolving credit facility  Company is positioned to meet all of its covenant calculations for the long term  Liquidity of ~$38 million (2) positions the company to take advantage of distressed sellers  Actively looking to consolidate Delaware basin working interest position  Management continues to pursue and execute on non-core asset sales Balance Sheet Positioned for the Downturn with Solid Liquidity & Financial Flexibility  6 gross (4.7 net) operated Bakken/Three Forks DUCs (drilled uncompleted) at the Stenehjem pad provide confidence in production guidance for FY:2016  Total Capex of $40 million funded out of cash flow and offering proceeds provides 4% YoY production growth at the midpoint of the 2016 guidance range Visible Production Growth and Fully Funded Capex Program Seasoned and Aligned Executive Management Team  CEO has been at the helm for ~40 years and has navigated numerous downturns  Management and affiliates own ~10% of the company (1) Company has $5.8 million of debt associated with a rig loan and building mortgage. (2) As of May 25, 2016.

7 Area Capital ($MM) % of Total Gross Wells Net Wells Permian - Delaware $10.0 25.0% 2.0 1.0 Austin Chalk 5.7 12.5% 1.0 1.0 Bakken 12.0 45.0% 7.0 5.0 Other 12.3 17.5% Total $40.0 100% 10.0 7.0 2016 Operating and Financial Guidance 2016 Capex Budget Allocation 2016 Operating Guidance Operating Costs Low Case High Case LOE ($/BOE) $8.0 $10.5 Production Tax (% Rev) 9.0% 12.0% Cash G&A ($mm) $8.0 $12.0 Production (boepd) 6,000 6,400 (1) Yearly CAPEX for each year ending December 31, 2011, 2012, 2013, 2014 and 2015. 2016 represents the midpoint of guidance. (2) 2016 estimate assumes the midpoint of 2016 guidance of 6,000 – 6,400 boepd. (Boep d) Daily Production vs Yearly CAPEX(1) Ye arl y C ap ex ($ M) 3,484 3,937 4,298 5,720 5,975 6,200 $0 $50,000 $100,000 $150,000 $200,000 $250,000 0 1,00 2,000 3,000 4,000 5,000 6,000 7,000 20 11 A 20 12 A 20 13 A 20 14 A 20 15 A 20 16 E ( 2)

8 Asset Base Overview

9 Abraxas Delaware Basin Assets Wolfcamp & Bone Spring Potential  5,227 net HBP acres located on the eastern edge of the Delaware Basin in Reeves/Ward County ▫ 42 gross / 27 net geologically risked potential horizontal locations ▫ Assumes one prospective zone (Third Bone Spring/Wolfcamp A)  Prospective for the Wolfcamp and Bone Spring intervals ▫ Average thickness for both sections ranges from 300’ – 500’  Offset operator 24-hour IP’s up to 1,700 Boe/d (~84% oil)  $5.95 million D&C costs for 5,000’ laterals  Targeted EURs of ~500 mboe  2016 Capex plans call for drilling 1 net (2 gross) well and additional acquisitions and leasing for total cost of $10 million  Multiple offers made to consolidate working interests in units  Exploring additional opportunities to expand position

10 Wolfcamp Overpressure Well along strike to AXAS leases Luo et al 1994 A A’ A A’ Contours are amount of overpressure in MPa (10 MPa = 1450 psi)

11  3rd Bone Spring and Wolfcamp A thickness similar to basinal wells  Horizontals target top of Wolfcamp  Lower Wolfcamp interval much thicker in basin 3rd Bone Spring and Wolfcamp Comparison of Abraxas Leases to WC/BS Horizontal Activity Target

12 3rd Bone Spring and Wolfcamp Abraxas Lease Areas:  3rd Bone Spring and Wolfcamp A present, relatively consistent  Lower Wolfcamp and underlying Penn. interval, variable

13 3rd Bone Spring-Wolfcamp A Thickness  Isopach (Thickness) Map of 3rd Bone Spring & Wolfcamp A with Wolfcamp/Bone Spring wells drilled after January 1, 2012  Contour interval = 25 ft ▫ Purple is thick (600-700 ft) ▫ Green is moderate (400-550 ft) ▫ Red is thin (250 ft)  Recent well results ▫ Jagged Peak wells reflecting significant outperformance vs. ~500 Mboe EUR type curve ▫ Pecos County - Parsley operated Tree State 16 recorded Company’s 2nd best 30 day IP rate per 1,000’ at 252 boe/d ▫ Felix Energy Holdings II – Recently permitted four wells offsetting Abraxas R.O.C. acreage (dashed red lines) ▫ Entire AXAS acreage block prospective for Wolfcamp and 3rd Bone Spring offering significant upside to estimated net locations Whiskey River 0927-7-1H (Jagged Peak) Peak 24-hour IP: 1,728 Boe/d Lateral Length: 9,442’ Target: Wolfcamp Whiskey River 0927-7-2H (Jagged Peak) Peak 24-hour IP: 1,774 Boe/d Lateral Length: 9,857’ Target: Wolfcamp Tree State 16-1H (Parsley Energy) Peak 24-hour IP: 1,558 Boe/d Peak 30-day IP: 1,151 Boe/d Lateral Length: 4,562’ Target: Wolfcamp Cilantro 2524-C3-1H (Jagged Peak) Peak 24-hour IP: 2,175 Boe/d Peak 30-day IP: 1,501 Boe/d Lateral Length: 8,279’ Target: Wolfcamp Whiskey River 98-34-2H(Jagged Peak) Recently completed Lateral Length: ~10,000’ Target: Wolfcamp Pyote Flats 98-34-1H (Jagged Peak) 11 mos Oil / Gas cum.: 161 mbo / 182 mmcf Lateral Length: ~10,000’ Target: Wolfcamp Felix Energy Holdings II, LLC Recent Permits

14 Strong Offset Operator Results  Abraxas’ acreage is located on the eastern platform of the play  Jagged Peak has been the most active operator in the area to date achieving attractive results in both the Wolfcamp and Bone Spring ▫ 3 month cum avg: 56,000 boe ▫ 6 month cum avg: 90,000 boe Jagged Peak Ten Well Cum Results(1) Pyote Flats Whiskey River 98-34 Eiland Trinity 15-33 1H (Bone Spring) Whiskey River 1H Cilantro Whiskey River 2H (1) Jagged Peak cumulative production data from the Texas Railroad Commission / HPDI.

15 Bakken / Three Forks North Fork/Lillibridge Potential  3,902 net HBP acres located in the core of the Williston Basin in Mckenzie County, ND – de-risked Bakken and Three Forks ▫ 30 operated completed wells ▫ 6 operated wells waiting on completion ▫ Expected to bring on production 3Q16 ▫ 1 non-operated well waiting on completion ▫ Expected to bring on production 1Q17 ▫ 9 planned multi-well pads at 660 ft. spacing ▫ 60 additional operated wells at 660-1320 foot spacing ▫ Additional upside potential from 3rd bench of the Three Forks  Average 30-day IPs of 999 Boe/d on last 25 wells drilled  2016 Capex plans call for the completion of 5.0 net (7.0 gross) wells for total cost of $18.0 million

16 Well Objective Lat. Length (1) Stages (1) 30-day IP (boepd) (1,2) Status Ravin 1H Three Forks 10,000 23 391 Producing Stenehjem 1H Middle Bakken 6,000 17 688 Producing Jore Federal 3H Three Forks 10,000 35 510 Producing Ravin 26-35 2H , 3H Middle Bakken 10,000 16 524 Producing Lillibridge 2H, 4H Three Forks 9,000 28 940 Producing Lillibridge 1H, 3H Middle Bakken 10,000 33 1,283 Producing Lillibridge 6H, 8H Three Forks 10,000 33 971 Producing Lillibridge 5H, 7H Middle Bakken 10,000 34 1,027 Producing Jore 1H Three Forks 10,000 33 1,037 Producing Jore 2H, 4H Middle Bakken 10,000 33 904 Producing Ravin 4H, 5H, 6H, 7H Middle Bakken 10,000 33 1,254 Producing, first MB downspacing test Stenehjem 2H, 4H Three Forks 10,000 33 863 Producing, first TF downspacing test Stenehjem 3H Middle Bakken 10,000 33 1,057 Producing Jore 5H, 6H, 7H, 8H Middle Bakken 10,000 33 819 Producing Stenehjem 5H Middle Bakken 10,000 33 809 Producing Sten-Ravin 1H, Ravin 8H Three Forks 10,000 33 900 Producing Stenehjem 10H Three Forks 10,000 NA NA Lateral cased Stenehjem 11H Middle Bakken 10,000 NA NA Lateral cased Stenehjem 12H Three Forks 10,000 NA NA Lateral cased Stenehjem 13H Middle Bakken 10,000 NA NA Lateral cased Stenehjem 14H Three Forks 10,000 NA NA Lateral cased Stenehjem 15H Middle Bakken 10,000 NA NA Lateral cased Bakken / Three Forks Focused on Execution (1) Represents the approximate, average lateral length, number of stages and 30-day IP for each group of wells. (2) The production rates for each well do not include the impact of natural gas liquids and shrinkage at the processing plant and include flared gas.

17 Bakken / Three Forks Exceptional Well Performance versus Type Curve 12/31/14 Type Curve = 420 MBO/well 12/31/15 Type Curve = 440 MBO/well

18 Austin Chalk Jourdanton First 2 AC wells  7,776 total net acres located in the Jourdanton Field perspective for the Austin Chalk in Atascosa County, TX ▫ 90+ wells of Austin Chalk potential  $5.0 million D&C costs for 5,000’ laterals  Targeted EURs of ~400 mbo for 5,000’ lateral  2016 Capex plans call for drilling 1 net (1 gross) 5,700’ lateral well for total cost of $5.7 million

19 Atascosa Trough Vertical Chalk Production (Cumulative Oil) Jourdanton Lease Block Karnes Trough Atascosa Trough

20 Karnes Trough Vertical and Horizontal Austin Chalk Production (Cumulative Oil) Blackbrush Kolodziej-Pawelek Unit 102H CUM Production Oil: 208 MBO Gas: 389 MMCF 7 Months EOG Leonard AC Unit 101H 30-Day IP: 2,100 Bopd and 2,715 Boepd CUM Production Oil: 65 MBO Gas: 87MMCF 1 Month Blackbrush Annie Trail/Yanta 11 – 14 Months

21 Key Investment Highlights  5,227 net HBP acres prospective for the Wolfcamp A & Bone Spring intervals  Recent Wolfcamp A & Bone Spring offset results demonstrate +1,500 boe/d 24-hour average rates  Plan to drill two 5,000 ft. Wolfcamp A laterals to test acreage in 2016 with first well to spud in July  Currently drilling first 5,700 ft. lateral Austin Chalk well test Emerging Delaware Basin and Austin Chalk Exposure  Total bank debt of $93 million (2) represents the only meaningful leverage (1, 2) of the company and is funded under recently re-determined $130 million revolving credit facility  Company is positioned to meet all of its covenant calculations for the long term  Liquidity of ~$38 million (2) positions the company to take advantage of distressed sellers  Actively looking to consolidate Delaware basin working interest position  Management continues to pursue and execute on non-core asset sales Balance Sheet Positioned for the Downturn with Solid Liquidity & Financial Flexibility  6 gross (4.7 net) operated Bakken/Three Forks DUCs (drilled uncompleted) at the Stenehjem pad provide confidence in production guidance for FY:2016  Total Capex of $40 million funded out of cash flow and offering proceeds provides 4% YoY production growth at the midpoint of the 2016 guidance range Visible Production Growth and Fully Funded Capex Program Seasoned and Aligned Executive Management Team  CEO has been at the helm for ~40 years and has navigated numerous downturns  Management and affiliates own ~10% of the company (1) Company has $5.8 million of debt associated with a rig loan and building mortgage. (2) As of May 25, 2016.

22 Appendix

23 Additional Assets Opportunity Overview Abraxas Assets 2016 Development Powder River Basin  Stacked pay, liquids-rich horizontal opportunities in Campbell, Converse and Niobrara Counties, Wyoming  Primarily in Converse and Campbell counties  Appx 2,088 net acres at Porcupine and 14,245 net acres at Brooks Draw  Hedgehog State 16-2H: Cum prod. (38 mos): 366 mboe, 23% Oil  No capital budgeted for 2016 Other Permian Basin  Large inventory conventional and unconventional targets  Emerging, oil-focused horizontal drilling opportunities  28,370 total net acres  Average production 856 boepd, ~23% oil (1)  No capital budgeted for 2016 Raven Drilling  Abraxas 100% wholly owned subsidiary  $15.8 million in NBV secured against $1.9 million in rig debt (2)  One 2,000 horsepower, SCR walking rig currently pad drilling in the Bakken  Subsidiary includes man camp and additional related rig equipment  No capital budgeted for 2016 Surface / Yards / Field Offices / Building  Surface ownership in numerous legacy areas  Net book value of $11.2 million (3)  Surface : 610 acres Scurry, TX; 1,769 acres in San Patricio, TX; 12,178 acres Pecos, TX; 590 acres McKenzie, ND; 50 acres DeWitt, TX; 15 acres Atascosa, TX  Yards/Offices/Structures: Sinton, TX; Scurry, Texas; McKenzie, ND;  21,000 square foot office building  No capital budgeted for 2016 (1) Average for month of December 31, 2015 (2) As of March 31, 2016 (3) As of December 31, 2015

24 Abraxas’ Eagle Ford Properties ~10,819 Net Acres Jourdanton Area  Atascosa County  Black oil  7,352 net acres Cave Area  McMullen County  Black oil  411 net acres Dilworth East Area  McMullen County  Oil/condensate  1,148 net acres Yoakum Area (not shown)  Dewitt and Lavaca County  Dry gas  1,908 net acres Jourdanton Area Cave Area Dilworth East Area

25 Eagle Ford Jourdanton Jourdanton  7,352 net acre lease block, 100% WI  90+ well Eagle Ford potential  North Fault Block ▫ Held by production ▫ Eight wells drilled ▫ 36+ additional potential well locations  South Fault Block ▫ One well drilled ▫ 42+ additional potential well locations

26 Eagle Ford Dilworth East Dilworth East  1,148 acre lease block, 100% WI  11 additional locations (red) ▫ Eight, 5,000-5,500’ lateral locations ▫ Three, 8,500’ lateral locations  R. Henry 2H ▫ 30 day IP: 780 boepd (1) ▫ On production  R. Henry 1H ▫ 30 day IP: 703 boepd (1) ▫ On production (1) The production rates for each well do not include the impact of natural gas liquids and shrinkage at the processing plant and include flared gas.

27 Eagle Ford Cave Cave  411 net acre lease block, 100% WI  Lower Eagle Ford fully developed ▫ Four 9,000’ lateral locations  Best month cumulative oil shown in green ▫ Offset operators : 8-10 mbo ▫ Abraxas Dutch 2H: 29 mbo  Dutch 1H ▫ 30 day IP: 786 boepd (1)  Dutch 2H ▫ 30 day IP: 1,093 boepd (1)  Dutch 3H ▫ 30 day IP: 888 boepd (1)  Dutch 4H ▫ 30 day IP: 926 boepd (1) (1) The production rates for each well do not include the impact of natural gas liquids and shrinkage at the processing plant and include flared gas.

28 Well Area Lat. Length (1) Stages (1) 30-day IP (boepd) Status T-Bird 1H Nordheim 5,102 15 1,202 (2) Sold 13 WyCross Wells WyCross 5,000 – 7,500 18 – 29 466 – 1,184 (2,3) Sold Blue Eyes 1H Jourdanton 5,000 22 527 (2,4) Producing Snake Eyes 1H Jourdanton 5,000 18 759 (2,4) Producing Spanish Eyes 1H Jourdanton 5,000 19 213 (2,4) Producing Eagle Eyes 1H Jourdanton 3,800 18 249 (2,4) Producing Ribeye 1H Jourdanton 7,000 21 240 (2,4) Producing Ribeye 2H Jourdanton 7,000 28 389 (2,4) Producing Cat Eye 1H Jourdanton 7,000 26 491 (2,4) Producing Grass Farm 2H Jourdanton 5,000 29 193 (2,4) Producing Dutch 2H Cave 9,000 36 1,093 (2) Producing Dutch 1H Cave 9,000 37 786 (2) Producing Dutch 3H Cave 9,000 37 888 (2) Producing Dutch 4H Cave 9,000 37 926 (2) Producing R Henry 2H Dilworth East 5,000 19 780 (2) Producing R. Henry 1H Dilworth East 5,000 34 703 (2) Producing Eagle Ford Focused on Execution (1) Represents the approximate, average lateral length and number of stages for each well. (2) The production rates for each well do not include the impact of natural gas liquids and shrinkage at the processing plant and include flared gas. (3) Represents the range for WyCross wells. (4) 30 day IP equivalent to highest 30 days of production after the well was placed on sub-pump.

29 Powder River Basin Turner Sandstone Horizontal Play Powder River Basin: Turner Sandstone  Isopach of Turner thickness  Multiple producing vertical wells, tight sandstone  Horizontal exploitation with multi-stage fracs recently  Porcupine Area ▫ Approximately 2,088 net acres  Brooks Draw Area ▫ Approximately 14,245 net acres

30 Edwards (South Texas)  PDP: 6.9 bcfe (net)(3)  Previous risked offsetting PUD locations: 27.9 bcfe (net) (4) ▫ 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 (4) ▫ 20% ROR at $4.30/mcfe realized price (4) ▫ Refrac: $0.7 million well / 0.5 bcfe EUR / F&D $1.40/mcfe (4) ▫ 20% ROR at $1.98/mcfe realized price (4) Montoya / Devonian (Delaware Basin, West Texas)  PDP 17.1 bcfe (net) (3)  PUD locations: 22.5 bcfe (net) (4) ▫ 12 gross/ 6 net locations ▫ $22.1 million PV-10 value at $2.36 realized gas(3) Other  Eagle Ford Shale, Yoakum: 1,908 net acres / ~24 net locations, unbooked  Permian, Hudgins Ranch: 3 gross / 2.6 net PSUD locations, 9.1 bcfe (net) (4)  Williston Basin, Red River: 1 gross / .8 net PRUD location, 2.1 bcfe (net) (4) (1) Net of purchase price adjustments (2) PV10 calculated using strip pricing and internal reserve report as of 5/1/12; production and reserves as of 5/1/12. (3) Based on December 31, 2015 reserves. (4) Management estimate 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(2)  Reserves 7.613 bcfe(2)  Production $4,650/mcfe/day  Reserves: $.88/mcfe Abraxas’ “Hidden” Gas Portfolio

31 Sharon Ridge/Westbrook: Clearfork Trend  89 active wells ▫ San Andres, Glorietta, Clearfork ▫ Cooperative water flood on some leases  110 potential (1) new-drills, recompletes or workovers  Abraxas New Drill Type Curve ▫ 31 Mbo (100% oil) ▫ Gross/Net CWC: $0.75/$0.6 million Permian Basin Sharon Ridge - Westbrook: Clearfork Trend (1) Potential locations and prospective acres based on an internal geologic and technical evaluation of the area and offset activity. These locations have yet to be audited by our third party engineer Degolyer & Macnaughton.

32 Abraxas Hedging Profile (1) Straight line average price. Q2 2016 Q3 2016 Q4 2016 2017 2018 Oil Swaps (bbls/day) 1948 1948 2500 1908 1500 NYMEX WTI (1) $39.04 $39.04 $43.25 $55.39 $46.39

33 EBITDA Reconciliation EBITDA is defined as net income plus interest expense, depreciation, depletion and amortization expenses, deferred income taxes and other non-cash items. The following table provides a reconciliation of EBITDA and Adjusted EBITDA to net income for the periods presented. (In thousands) 2013 2014 2015 Net income $38,647 $63,268.73 ($119,055) Net interest expense 4,577 2,009 3,340 Income tax expense 700 (287) (37) Depreciation, depletion and amortization 26,632 43,139 38,548 Amortization of deferred financing fees 1,367 934 1,130 Stock-based compensation 2,114 2,703 3,912 Impairment 6,025 0 128,573 Unrealized (gain) loss on derivative contracts (2,561) (24,876) (18,417) Realized (Gain) loss on interest derivative contract 0 0 0 Realized (Gain) loss on monetized derivative contracts 0 0 5,061 Earnings from equity method investment 0 0 0 (Gain) loss on discontinued operations (33,377) (1,318) 20 Other non-cash items 539 0 883 EBITDA $44,663 $85,572 $43,957 Credit facility borrowings $33,000 $70,000 $134,000 Debt/EBITDA 0.74x 0.82x 3.05x

34 TTM EBITDA Reconciliation EBITDA is defined as net income plus interest expense, depreciation, depletion and amortization expenses, deferred income taxes and other non-cash items. The following table provides a reconciliation of EBITDA and Adjusted EBITDA to net income for the periods presented. (In thousands) Three Months End 31-Mar-15 30-Jun-15 30-Sep-15 31-Dec-15 TTM Net income $7,407 ($6,429) ($52,372) ($67,661) ($119,055) Net interest expense 694 816 847 983 3,340 Income tax expense 0 0 0 (37) (37) Depreciation, depletion and amortization 12,069 8,637 10,165 7,677 38,548 Amortization of deferred financing fees 644 162 162 162 1,130 Stock-based compensation 810 1,440 835 826 3,912 Impairment 0 0 59,891 68,682 128,573 Unrealized (gain) loss on derivative contracts (9,806) 5,470 (10,474) (3,608) (18,417) Realized (Gain) loss on interest derivative contract 0 0 0 0 0 Realized (Gain) loss on monetized derivative contracts 0 5,061 0 0 5,061 Earnings fro equity method investment 0 0 0 0 0 (Gain) loss on discontinued operations 20 0 0 0 20 Other non-cash items 139 143 144 457 883 EBITDA $11,977 $15,301 $9,199 $7,480 $43,957 Credit facility borrowings $134,000 Debt/EBITDA 3.05x

35 Standardized Measure Reconciliation PV-10 is the estimated present value of the future net revenues from our proved oil and gas reserves before income taxes discounted using a 10% discount rate. PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and gas properties and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2015: Total Proved 31-Dec-15 ($000) Futu e G oss Revenue $1,241,334 P oduction a d Ad Valorem Taxes (119,070) Oper ting Expenses (319,714) Capital Cost (338,316) Abandonment Costs (1,322) Future Net Revenue 462,912 Present Worth at 10 Percent $197,251 Present value of future income taxes discounted at 10% 0 Standardized measure of discounted future net cash flows $197,251

36 NASDAQ: AXAS