Abraxas Petroleum Corporate Update November 2017 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. 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)............................ 86 Shares outstanding(2)……......... 165.9 mm Market cap(2) …………………….... $353.3 mm Net debt(2)……………………………. $66.9 mm 2017E CAPEX……………………….. $120 mm (1) Abraxas full time employees as of August 9, 2017. Does not include 26 employees associated with the Company’s wholly owned subsidiary, Raven Drilling. (2) Shares outstanding as of September 30, 2017. Market cap using share price as of October 31, 2017. Total debt including RBL facility and building mortgage less cash as of September 30, 2017 (3) Enterprise value includes working capital deficit (excluding current hedging assets and liabilities) as of September 30, 2017, but does not include building mortgage. Includes RBL facility and building mortgage less cash as of September 30, 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 September 30, 2017. (6) Average production for the quarter ended September 30, 2017 (7) Calculation using average production for the quarter ended September 30, 2017 annualized and net proved reserves as of December 31, 2016. EV/BOE(2,3)…………………………… $9.76 Proved Reserves(4)………………. . 44.7 mmboe NBV Non-Oil & Gas Assets(5)… $21.3 mm Production(6).……………………….. 8,745 boepd R/P Ratio(7)…………………………… 14.0x NASDAQ: AXAS Corporate Profile

4 Key Investment Highlights  Recent well completion in Eagle Ford testing modern completion techniques currently flowing back  First Austin Chalk completion confirmed geologic concept  No capital allocated in 2018  Evaluating options to maximize value of the assets Austin Chalk/ Eagle Ford Optionality  Total bank debt of ~$64 million (2) represents the only meaningful leverage (1, 2) of the Company  Liquidity of ~$71 million (2) positions the Company to remain acquisitive  Management continues to pursue and execute on non-core asset sales  2018 Drilling and Completion CAPEX forecasted to remain within cash flow (3) Balance Sheet Strength with Solid Liquidity & Financial Flexibility  10 gross (7.0 net) operated Wolfcamp/Bone Spring wells planned for 2018  10 gross (4.7 net) operated and non-operated Bakken/Three Forks wells planned for 2018  Total drilling and completion CAPEX of $90 million funded out of cash flow provides 44% YoY production growth using the midpoints of 2017 and 2018 guidance Visible Production Growth and Fully Funded Capex Program (1) Company also has $3.7 million of debt associated with a building mortgage. (2) As of September 30, 2017. (3) Based on guidance provided on slide 5. Assumes strip pricing as of October 31, 2017.  8,131 net HBP acres prospective for the Wolfcamp A, B & Bone Spring intervals  Multi-zone development across acreage position  Continue to actively lease and pursue acquisitions – recent acquisitions of 2,500+ net acres  Allocated 2018 capital budget of $51 million (57% of total allocation) Delaware Basin Exposure

5 2018 Operating and Financial Guidance 2018 Capex Budget Allocation 2018 Operating Guidance Operating Costs Low Case High Case LOE ($/BOE) $4.00 $6.00 Production Tax (% Rev) 8.0% 9.0% Cash G&A ($mm) $8.5 $12.5 Production (boepd) 10,000 12,000 (1) Yearly CAPEX for each year ending December 31, 2013, 2014, 2015 and 2016. 2017 and 2018 based on midpoint of management guidance. (2) Average estimated production for 2017 and 2018 based on the midpoint of management guidance. 66% 22% 12% 2018 Expected Production Mix Oil Gas NGL $0 $50,000 $100,000 $150,000 $200,000 $250,000 0 2,000 4,000 6,000 8,000 10,000 12,000 20 13 A 20 14 A 20 15 A 20 16 A 20 17 E (2 ) 20 18 E (2 ) Daily Production vs Yearly CAPEX (1) Area Capital ($MM) % of Total Gross Wells Net Wells Permian - Delaware $51.0(1) 56.6% 10.0 7.0 Bakken/Three Forks 33.8 37.6% 10.0 4.7 Eagle Ford/Austin Chalk 0.0 0.0% 0.0 0.0 Facilities/Other 5.2 5.7% 0.0 0.0 Total $90.0 100% 20.0 11.7

6 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 Bakken/Three Forks Wolfcamp Eagle Ford Abraxas CAPEX & Production Outlook (1) 2017-2019 in Boepd Assumes one rig in the Bakken/Three Forks and one rig in the Delaware D&C CAPEX(3) $90mm $90mm $90mm PDP (2) Incremental Bakken/ Three Forks (2) Incremental Wolfcamp (2) Incremental Eagle Ford/ Austin Chalk (2) B ar re ls o f Eq u iv al e n t p e r D ay ( B o e p d ) (1) Production and CAPEX guidance based on internal management estimates. The 2017, 2018 and 2019 production and capital expenditure guidance is subject to change depending upon a number of factors, including the availability of drilling equipment and personnel, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources for drilling prospects, the Company’s financial results, the availability of leases on reasonable terms and the ability of the Company to obtain permits for drilling locations. (2) Projected PDP volumes are based on management’s internal estimates and account for all recent completions and acquisitions. The rates of decline are estimates and actual production declines could be materially higher. Incremental Bakken/Three Forks, Wolfcamp and Eagle Ford/Austin Chalk projections are based on the Company’s type curves. (3) D&C CAPEX includes only capital expenditures associated with drilling, completions and facilities. Excludes approximately $30 million associated with acquisitions consummated during 2017.

7 Implied Value Per Acre(1,2) (1) Calculated as Enterprise Value less reserve/production value divided by net acres. Enterprise value calculated using market cap as of October 31, 2017 and most recent publicly available balance sheet. Production/reserve value calculated as $35,000/Boepd multiplied by most recent quarters average daily production. (2) Peers include: Callon Petroleum, Centennial Development, Diamondback, Halcon, Jagged Peak, Lillis Energy, Parsley Energy, Rosehill Resources, RSP Permian. Halcon numbers are pro forma for recent divestitures and tender offers. Lillis Energy numbers are pro forma for recent transactions. (3) Enterprise value of Abraxas calculated as market cap as of October 31, 2017 and net debt as of September 30, 2017. Abraxas production value calculated as $35,000/Boepd multiplied by 3Q17 production of 8,745 Boepd. Update $0 $10,000 $20,000 $30,000 $40,000 $50,000 $60,000 Peer 1 (1) Peer 2 (1) Peer 3 (1) Peer 4 (1) Peer 5 (1) Peer 6 (1) Peer 7 (1) Peer 8 (1) Peer 9 (1) Peer 10 (1) Average AXAS (3)

8 Asset Base Overview

9  8,131 net HBP acres located in the eastern core of the Delaware Basin  Up to five identified potential zones (Bone Spring, Wolfcamp) ▫ 160+ gross operated identified potential locations ▫ 320+ gross operated identified potential locations with downspacing ▫ 100+ gross non-operated identified potential locations  Unique, legacy high value acreage ▫ Favorable net revenue interests – in many cases 1/8th royalty ▫ 95+% held by production  Infrastructure ▫ Two water supply wells ▫ Two 400,000 bbl lined frac pits, ▫ SWD wells and system in place  Exploring additional opportunities to expand position Delaware Basin Permian Basin – Wolfcamp & Bone Spring – Ward/Reeves Map Source: Callon, Jagged Peak, Halcon, Diamondback presentations, Drilling Info and management estimates.

10 9 Univ Lands Beldin 3H Jagged Peak IP24: 1,415 BOEPD (81% Oil) LL: 9,561’ Surrounding Delaware Activity 1 Sealy Ranch 9301H Halcon LL: 10,000’ 2 Univ Lands Beldin 4H Jagged Peak LL: 10,000’ 3 Caprito 82 202H Abraxas LL: 5,000’ 4 Caprito 82 101H Abraxas LL: 5,000’ 5 Sealy Ranch 7903H Halcon LL: 10,000’ 6 Sealy Ranch 7902H Halcon LL: 10,000’ 7 Caprito 83 304H Abraxas LL: 5,000’ 8 Caprito 83 404H Abraxas LL: 5,000’ 10 Caprito 99 302H Abraxas IP: 997 BOEPD (83% Oil) LL: 4,529’ 11 Caprito 98 301HR Abraxas IP30: 999 BOEPD (84% Oil) LL: 5,000’ 12 Caprito 98 201H Abraxas IP30: 1,036 BOEPD (84% Oil) LL: 5,000’ 13 CRMWD-79 1H Halcon IP30: 1,343 BOEPD (80% Oil) LL: 3,477’ 14 St. Quadricorn 1617A 1H Jagged Peak Flowback Test: 1,500 BOEPD LL: 10,000’ 17 Whiskey River 5-8 Jagged Peak LL:10,000’ 19 Sealy Ranch 7703H Halcon LL: 10,000’ 15 State 5913A 1H Jagged Peak LL: 9,000’ 18 Sealy Ranch 7701H Halcon LL: 10,000’ 14 15 16 16 State 5913A 2H Jagged Peak LL: 9,000’ 17

11 Delaware Basin Caprito Development Plan (1) (1)  First Pad – Caprito 98-201H & Caprito 98-301HR ▫ Wolfcamp A1 – Caprito 201H – producing ▫ Wolfcamp A2 – Caprito 301HR – producing  Second Pad – Section 83 Pad – Two Well Pad ▫ Wolfcamp A2 – Caprito 83-304H – flowing back ▫ Wolfcamp B – Caprito 83-404H – remediated; waiting on completion  Third Pad – Section 82 Pad – Two Well Pad ▫ Wolfcamp A1 – Caprito 82-202H – waiting on completion ▫ Third Bone Spring – Caprito 82-101H – waiting on completion  Fourth Pad – Section 99 Pad – Four Well Pad ▫ Wolfcamp A1 – Caprito 99-211H and 202H – downspacing test - drilling ▫ Wolfcamp A2 – Caprito 99-301H and 311H – downspacing test - drilling

Delaware Wolfcamp Wolfcamp A2 Well Economics Wolfcamp: ROR vs WTI Wolfcamp: Type Curve Assumptions Abraxas EOY16 Assumptions  604 MBOE gross type curve ▫ 77% Oil ▫ Initial rate: 1266 boepd ▫ di: 99.95% ▫ dm: 6.0% ▫ b-factor: 1.3  Assumed CWC: $7.0 million 12

13 Bakken/Three Forks 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 ▫ 41 operated completed wells ▫ Estimated 32 gross additional operated wells ▫ Estimated 36 gross/3 net additional non-operated locations ▫ 3 operated wells completing ▫ 3 operated wells drilling  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 ▫ 62.0% net revenue interest ▫ 30-day MB average rate(1) 1,148 boepd ▫ 30-day TF average rate(1) 1,143 boepd  Yellowstone 2H-4HR ▫ Three well pad completing ▫ 42.7% net revenue interest  Yellowstone 5H-7H ▫ Three well pad currently drilling (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.

14 Bakken/Three Forks Completion Design Highlights • Cemented liners and high density perf clusters o create more frac points o enhance SRV o help localize the stimulation. • PLA diverters o used to increase cluster efficiency • Focusing on increasing total energy o more fluid & prop usage o higher pump rate Metrics • Prop - 870 lbs/ft • Fluid – 15 bbls/ft • Fluid type - HCFR • Staging – 240’/stage • Clusters – 12 /stage • Perfs – 2/cluster, 180 deg phase • Pump rate – 50 BPM

15 Shut Eye 1H  9,360 net acres located in Atascosa County, TX prospective for the Eagle Ford and Austin Chalk  Shut Eye 1H – EF Test ▫ Flowing back ▫ Enhanced completion design  Evaluating options to maximize value of the asset Jourdanton Eagle Ford/Austin Chalk

16 Eagle Ford Enhanced Completion Design Highlights • Employing high density clusters and diverters for first time o create more frac points o increase cluster efficiency o enhance SRV o help localize the stimulation. • Focusing on increasing total energy o more prop & fluid usage • Using rotary steerable assemblies o will help ensure that the borehole is in the targeted rock Metrics • Prop - 2000 lbs/ft • Fluid – 40 bbls/ft • Fluid type - HCFR • Staging – 240’/stage • Clusters – 12 /stage • Perfs – 2/cluster, 180 deg phase • Pump rate – 70 BPM

17 Focusing the Portfolio Executed Asset Sales (1) Includes $6.7 million for Abraxas’ 12,178 net acre ranch which was used as consideration for the Company’s July 2017 Ward County acquisition. Since January 1, 2016, Abraxas has monetized approximately $41.6 million(1) of non-core assets. Abraxas is currently marketing 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  Stacked pay, liquids-rich horizontal opportunities in Campbell, Converse and Niobrara Counties, Wyoming  ~14,229 net acres at Brooks Draw  2,667 “other” net acres  2,088 net acres at Porcupine  ~128 bopd net production  Brooks Draw Sold January 2017  Portion of Porcupine and “other” acres Sold July 2017  Remainder Sold October 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  San Patricio ranch sold September 2016  Sinton office sold May 2017  Hudgins (Pecos County) swapped for additional Delaware Basin interests

18 Appendix

19 (1) Straight line average price. Abraxas Hedging Profile 4Q17 2018 2019 Oil Swaps (bbls/day) 4,063 2,651 1,200 NYMEX WTI (1) $52.82 $48.53 $54.54 WTI Midland / WTI CMA (bbls/day) 500 Differential ($/bbl) ($0.65) Henry Hub Costless Collar (mmbtu/day) 5,000 Ceiling ($/mmbtu) $3.90 Floor ($/mmbtu) $3.00

20 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

21 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) 31-Dec-16 31-Mar-17 30-Jun-17 30-Sep-17 TTM Net income ($5,302) $13,691 $7,194 ($770) $14,813 Net interest expense 859 395 389 753 $2,396 Income tax expense 0 0 0 0 $0 Depreciation, depletion and amortization 6,500 5,374 4,415 7,878 $24,166 Amortization of deferred financing fees 256 138 116 100 $610 Stock-based compensation 784 770 979 750 $3,283 Impairment 0 0 0 0 $0 Unrealized (gain) loss on derivative contracts 6,285 (8,760) (5,071) 6,873 ($674) Realized (Gain) loss on interest derivative contract 0 0 0 0 $0 Realiz d (Gain) loss on monetized derivative contracts 0 0 0 0 $0 Earnings from equity method investment 0 0 0 0 $0 (G i ) l ss o i continued operations 0 0 0 0 $0 Expenses incurred with offerings and execution of loan agreement 0 3,790 703 199 $4,692 Other non-cash items 139 112 113 113 $477 EBITDA $9,521 $15,507 $8,838 $15,896 $49,762 Credit facility borrowings $64,250 Debt/EBITDA 1.29x

22 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

23 NASDAQ: AXAS