Abraxas Petroleum Corporate Update April 2017 Raven Rig #1; McKenzie County, ND

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. Oil and Gas Reserves. The SEC permits oil and natural gas companies, in their SEC filings, to disclose only reserves anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. We use certain terms in this presentation, such as total potential, de-risked, and EUR (expected ultimate recovery), that the SEC’s guidelines strictly prohibit us from using in our SEC filings. These terms represent our internal estimates of volumes of oil and natural gas that are not proved reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery techniques and are not intended to correspond to probable or possible reserves as defined by SEC regulations. By their nature these estimates are more speculative than proved, probable or possible reserves and subject to greater risk they will not be realized. Non-GAAP Measures. Included in this presentation are certain non-GAAP financial measures as defined under SEC Regulation G. Investors are urged to consider closely the disclosure in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016 and its subsequently filed Quarterly Reports on Form 10-Q and Current Reports on Form 8-K and the reconciliation to GAAP measures provided in this presentation. Initial production, or IP, rates, for both our wells and for those wells that are located near our properties, are limited data points in each well’s productive history. These rates are sometimes actual rates and sometimes extrapolated or normalized rates. As such, the rates for a particular well may change as additional data becomes available. Peak production rates are not necessarily indicative or predictive of future production rates, expected ultimate recovery, or EUR, or economic rates of return from such wells and should not be relied upon for such purpose. Equally, the way we calculate and report peak IP rates and the methodologies employed by others may not be consistent, and thus the values reported may not be directly and meaningfully comparable. Lateral lengths described are indicative only. Actual completed lateral lengths depend on various considerations such as lease- line offsets. Standard length laterals, sometimes referred to as 5,000 foot laterals, are laterals with completed length generally between 4,000 feet and 5,500 feet. Mid-length laterals, sometimes referred to as 7,500 foot laterals, are laterals with completed length generally between 6,500 feet and 8,000 feet. Long laterals, sometimes referred to as 10,000 foot laterals, are laterals with completed length generally longer than 8,000 feet. Forward-Looking Statements

3 Headquarters......................... . San Antonio Employees(1)............................ 84 Shares outstanding(2)……......... 163.9 mm Market cap(2) …………………….... $317.9 mm Net debt(2)……………………………. $22.8 mm 2017E CAPEX……………………….. $110 mm (1) Abraxas full time employees as of February 28, 2017. Does not include 25 employees associated with the Company’s wholly owned subsidiary, Raven Drilling. (2) Shares outstanding as of February 1, 2017. Market cap using share price as of March 30, 2017. Total debt including RBL facility and building mortgage less cash as of February 1, 2017 (3) Enterprise value includes working capital deficit (excluding current hedging assets and liabilities) as of December 31, 2016, but does not include building mortgage. Includes RBL facility and building mortgage less cash as of February 1, 2017. (4) Proved reserves as of December 31, 2016. See appendix for reconciliation of PV-10 to standardized measure. (5) Net book value of other assets as of December 31, 2016. (6) Average production for the quarter ended December 31, 2016. (7) Calculation using average production for the quarter ended December 31, 2016 annualized and net proved reserves as of December 31, 2016. EV/BOE(2,3)…………………………… $7.64 Proved Reserves(4)………………. . 44.7 mmboe NBV Non-Oil & Gas Assets(5)… $22.5 mm Production(6).……………………….. 7,953 boepd R/P Ratio(7)…………………………… 15.4x NASDAQ: AXAS Corporate Profile

4 Williston: Bakken / Three Forks Eastern Shelf: Conventional & Emerging Hz Oil Eagle Ford Shale / Austin Chalk Delaware Basin: Bone Spring & Wolfcamp Rocky Mountain South Texas Permian Basin Legend Proved Reserves (mmboe)(1): 44.7  Proved Developed: 31%  Oil: 54% Current Prod (boe/d) (2): 7,953 Abraxas Petroleum Corporation Core Regions (1) Net proved reserves as of December 31, 2016. (2) Average production for quarter ended December 31, 2016 2017 Capex Focus Areas

5 Area Capital ($MM) % of Total Gross Wells Net Wells Permian - Delaware $52.5 47.7% 7.0 6.0 Bakken/Three Forks 42.2 38.4% 13.0 6.6 Austin Chalk 11.0 10.0% 2.0 2.0 Other 4.3 3.9% 0.0 0.0 Total $110.0 100% 22.0 14.6 2017 Operating and Financial Guidance 2017 Capex Budget Allocation 2017 Operating Guidance Operating Costs Low Case High Case LOE ($/BOE) $6.00 $8.00 Production Tax (% Rev) 8.0% 10.0% Cash G&A ($mm) $10.0 $12.5 Production (boepd) 7,800 8,600 (1) Yearly CAPEX for each year ending December 31, 2012, 2013, 2014, 2015 and 2016. 2017 based on management guidance. (2) 2017 estimates assume the midpoint of 2017 guidance. 66% 22% 12% 2017 Expected Production Mix Oil Gas NGL $0 $50,000 $100,000 $150,000 $200,000 $250,000 0 1,500 3,000 4,500 6,000 7,500 9,000 2 0 12 A 2 0 13 A 2 0 14 A 2 0 15 A 2 0 16 A 2 0 17 E (2 ) Daily Production vs Yearly CAPEX (2)

6 Key Investment Highlights  Continue to evaluate Eagle Ford/Austin Chalk and add cost-effective leases  First well confirmed AC geologic concept  Two well program in 2017 designed to establish economic viability of both Eagle Ford and Austin Chalk via engineering and geologic modifications Austin Chalk/ Eagle Ford Optionality  Total bank debt of ~$20 million(3) represents the only meaningful leverage (2, 3) of the Company and is funded under the $115 million revolving credit facility  Liquidity of ~$95 million(3) positions the Company to remain acquisitive  Actively looking to consolidate Delaware Basin working interest position and surrounding leases  Management continues to pursue and execute on non-core asset sales Balance Sheet Strength with Solid Liquidity & Financial Flexibility  7 gross (6.0 net) operated Wolfcamp/Bone Spring wells planned for 2017  13 gross (6.6 net) operated and non-operated Bakken/Three Forks wells planned for 2017  Total Capex of $110 million funded out of cash flow and RBL provides 33% YoY production growth using the midpoint of 2017 guidance Visible Production Growth and Fully Funded Capex Program (1) Includes 480 net acres on Abraxas’ Howe lease which is currently subject to a title dispute. Abraxas does not have any reserves or planned 2017 capital expenditures relating to the acreage that is subject to this title dispute. Includes 28 acres to be earned on farm-in on Caprito 201 and 301. (2) Company also has $3.8 million of debt associated with a building mortgage. (3) As of February 1, 2017.  5,749(1) net HBP acres prospective for the Wolfcamp A & Bone Spring intervals  Plan to test multiple prospective zones in 2017  Continue to actively lease and pursue acquisitions in the basin  2017 capital budget increasing to $53MM (48% of total allocation) Delaware Basin Exposure

7 Asset Base Overview

8 Catalyst #1 Permian Basin – Wolfcamp & Bone Spring – Ward/Reeves  5,749(1) net HBP acres located on the eastern edge of the Delaware Basin in Reeves/Ward/Pecos County (Pecos not shown) ▫ Up to five identified potential zones (Bone Spring, Wolfcamp) ▫ Over 150 identified potential locations  $6.3 million D&C costs for 5,000’ laterals  Favorable net revenue interests  Wolfcamp A2 targeted EURs of ~650 mboe  First well – Caprito 99-302H – Wolfcamp A2 ▫ 30-Day IP Rate: 997 Boepd ▫ 90-Day IP Rate: 794 Boepd ▫ Exceeding type curve to date  Caprito 98-201H & Caprito 98-301H ▫ Intermediate set on both wells, currently drilling lateral on 201H ▫ June 2017 completion date scheduled ▫ Caprito 201H –target window Wolfcamp A1 “wine rack” spacing ▫ Caprito 301HR – target window Wolfcamp A2 (same as 99-302H)  Exploring additional opportunities to expand position (1) Includes 480 net acres on Abraxas’ Howe lease which is currently subject to a title dispute. Abraxas does not have any reserves or planned 2017 capital expenditures relating to the acreage that is subject to this title dispute. Includes 28 acres to be earned on farm-in on Caprito 201 and 301. (1) (1)

9 Delaware Basin Caprito Development Plan  First Pad – Caprito 98-201H & Caprito 98-301HR ▫ Caprito 201H –target window Wolfcamp A1 “wine rack” spacing ▫ Caprito 301HR – target window Wolfcamp A2 (same as 99-302H)  Section 83 Pad – Two Well Pad ▫ Wolfcamp A2 ▫ Wolfcamp B  Section 82 Pad – Two Well Pad ▫ Wolfcamp A1 ▫ Third Bone Spring  Results Will Dictate Future Development of Each Interval on Subsequent Pads (1) (1)

10 Delaware Basin Wine Rack Drilling and Completion  Phantom Field Spacing ▫ 1320’ between wells same zone ▫ 330’ between wells ▫ Pattern repeats for additional targets  Drilling Targets include 4 benches ▫ 3rd Bone Spring ▫ Upper Wolfcamp A1 ▫ Upper Wolfcamp A2 ▫ Wolfcamp B

11 Delaware Wolfcamp Wolfcamp A2 Well Economics Wolfcamp: ROR vs CAPEX (1) (1) Uses strip pricing as of March 28, 2017. Abraxas EOY16 Assumptions  604 MBOE gross type curve ▫ 77% Oil ▫ Initial rate: 1266 boepd ▫ di: 99.95% ▫ dm: 6.0% ▫ b-factor: 1.3  Booked CWC: $6.0 million Wolfcamp: Type Curve Assumptions

12 Catalyst #2 Bakken / Three Forks  4,013 net HBP acres located in the core of the Williston Basin in McKenzie County, ND – de-risked Bakken and Three Forks ▫ 37 operated completed wells ▫ 4 operated wells waiting on completion ▫ 1 non-operated well waiting on completion ▫ Estimated 53 additional operated wells at 660-1,320 foot spacing  Stenehjem 10H-15H Completions ▫ 64.2% net revenue interest ▫ 30-day MB average rate(1) 1,226 boepd ▫ 30-day TF average rate(1) 1,059 boepd  Stenehjem 6H-9H ▫ Four well pad drilled and waiting on completion ▫ May 2017 completion date scheduled ▫ 62.0% net revenue interest  Yellowstone 2H-4H ▫ Preparing to mobilize rig and spud three well pad ▫ 42.7% net revenue interest  Five gross non-operated wells planned for 2017 ▫ 9-36% working interest ▫ Operator testing three mile laterals (1) The 30-day average rates represent the highest 30 days of production and do not include the impact of natural gas liquids and shrinkage at the processing plant and include flared gas.

13 Middle Bakken North Fork Economics Middle Bakken: ROR vs CAPEX (1) (1) Uses strip pricing as of March 28, 2017. Middle Bakken: Type Curve Assumptions Abraxas EOY16 Assumptions  845 MBOE gross type curve ▫ 76% Oil ▫ Initial rate: 1120 boepd ▫ di: 98.5% ▫ dm: 8.0% ▫ b-factor: 1.5  CWC: $6.0 million

14 Three Forks North Fork Economics Three Forks: ROR vs CAPEX (1) (1) Uses strip pricing as of March 28, 2017. Three Forks: Type Curve Assumptions Abraxas EOY16 Assumptions  723 MBOE gross type curve ▫ 73% Oil ▫ Initial rate: 1000 boepd ▫ di: 98.5% ▫ dm: 8.0% ▫ b-factor: 1.5  CWC: $6.0 million

15 Next Well  7,685 total net acres located in the Jourdanton Field prospective for the Eagle Ford and Austin Chalk in Atascosa County, TX  $5.5 million D&C costs for 5,000’ laterals  2017 Capex plans call for drilling 2 net (2 gross) 5,000’ lateral wells for total cost of $5.5 million each  First AC well, Bulls Eye 101H ▫ 5,865’ effective lateral ▫ 30-Day IP Rate: 366 Boepd  Shut Eye 1H – EF Test ▫ Will hold AC acreage ▫ Enhanced completion design  Abraxas continues to evaluate acreage at terms that will ensure acceptable full cycle economics Jourdanton Eagle Ford/Austin Chalk

16 Catalyst #4 Potential Asset Sales (1) Average for the month of June, 2016 Since January 1, 2016, Abraxas has monetized approximately $26.9 million of non-core assets. Abraxas is currently marketing several additional non-core assets. If successful, proceeds will be used to further reduce borrowings with little Borrowing Base impact Opportunity Overview Abraxas Assets Status Powder River Basin - Other  Stacked pay, liquids-rich horizontal opportunities primarily in Campbell, Converse Counties, Wyoming  ~2,088 net acres at Porcupine  ~2,667 “other” acres  ~150 boepd (~45% oil) net production (1)  Bids not acceptable to date – will continue to explore opportunities to exit position Powder River Basin – Brooks Draw  Stacked pay, liquids-rich horizontal opportunities in Converse and Niobrara Counties, Wyoming  ~14,229 net acres  ~28 bopd net production  Sold January, 2017 Portilla  Large inventory conventional targets; EOR potential  Avg production ~150 boepd, ~87% oil  Sold September, 2016 Surface / Yards / Field Offices / Building  Surface ownership in numerous legacy areas  Surface :  1,769 acres in San Patricio, TX;  12,178 acres Pecos, TX;  Yards/Offices/Structures: Sinton, TX  Sinton office listed  Hudgins (Pecos County) listed

17 Appendix

18 Abraxas Hedging Profile (1) Straight line average price. 2017 2018 2019 Oil Swaps (bbls/day) 2,401 1,796 1,200 NYMEX WTI (1) $54.53 $47.48 $54.54 WTI Midland / WTI CMA (bbls/day) 500 Differential ($/bbl) ($0.65) Henry Hub Costless Collar (mmbtu/day) 5,000 Ceiling ($/mmbtu) $3.90 Floor ($/mmbtu) $3.00

19 Adjusted EBITDA Reconciliation Adjusted 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 Adjusted EBITDA to net income for the periods presented. (In thousands) Year End 2014 2015 2016 Net income $63,268.73 ($119,055) ($96,378) Net interest expense 2,009 3,340 $3,827 Income tax expense (287) (37) $0 Depreciation, depletion and amortization 43,139 38,548 $24,431 Amortization of deferred financing fees 934 1,130 $1,019 Stock-based compensation 2,703 3,912 $3,194 Impairment 0 128,573 $67,626 Unrealized (gain) loss on derivative contracts (24,876) (18,417) $19,818 Realized (Gain) loss on interest derivative contract 0 0 $0 Realized (Gain) loss on monetized derivative contracts 0 5,061 $14,370 Earnings from equity method investment 0 0 $0 (Gai ) loss o discontinued operations (1,318) 20 $0 Expenses incurred with offerings and execution of loan agreement $1,747 Other non-cash items 0 883 $494 EBITDA $85,572 $43,957 $40,149 Credit facility borrowings $70,000 $134,000 $93,250 Debt/EBITDA 0.82x 3.05x 2.32x

20 TTM Adjusted EBITDA Reconciliation Adjusted 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 Adjusted EBITDA to net income for the periods presented. (In thousands) Three Months Ending 31-Mar-16 30-Jun-16 30-Sep-16 31-Dec-16 TTM Net income ($40,880) ($46,937) ($3,260) ($5,302) ($96,378) Net interest expense 1,103 1,015 850 859 3,827 Income tax expense 0 0 0 0 0 Depreciation, depletion and amortization 5,892 5,669 6,371 6,500 24,431 Amortization of deferred financing fees 164 448 151 256 1,019 Stock-based compensation 807 835 768 784 3,194 Impairment 35,085 28,735 3,806 0 67,626 Unrealized (gain) loss on derivative contracts 4,642 12,374 (3,484) 6,285 19,818 Realized (Gain) loss on interest derivative contract 0 0 0 0 0 Realized (Gain) loss on monetized derivative contracts 4,360 10,010 0 0 14,370 Earnings from equity method investment 0 0 0 0 0 (G in) l s on discontinued operations 0 0 0 0 0 Expenses incurred with offerings and execution of loan agreement 0 1,665 82 0 1,747 Other non-cash items 583 36 (264) 139 494 EBITDA $11,756 $13,851 $5,021 $9,521 $40,149 Credit facility borrowings $93,250 Debt/EBITDA 2.32x

21 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: Tot l Pr v d 31-Dec-16 Future cash inflows $999,716 Future production costs (357,917) Future development costs (267,836) Discount (213,363) Present Worth at 10 Percent 160,600 Present value of future income taxes discounted at 10% 0 Standardized measure of discounted future net cash flows $160,600

22 NASDAQ: AXAS