Abraxas Sprinting Into 2017…. December 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 Headquarters.......................... San Antonio Employees(1)............................ 83 Shares outstanding(2)……......... 135.1 mm Market cap(4) …………………….... $283.6 mm Net debt(3)………………………….. $95.0 mm 2017E CAPEX………………………. $60 mm (1) Abraxas full time employees as of October 12, 2016. Does not include nine employees associated with the Company’s wholly owned subsidiary, Raven Drilling. (2) Shares outstanding as of September 30, 2016. (3) Total debt including RBL facility, rig loan and building mortgage less cash as of September 30, 2016. (4) Share price as of November 30, 2016. (5) Enterprise value includes working capital deficit (excluding current hedging assets and liabilities) as of September 30, 2016, but does not include building mortgage or rig loan. Includes RBL facility, rig loan and building mortgage less cash as of September 30, 2016. (6) Average production for the quarter ended September 30, 2016. (7) Calculation using average production for the quarter ended September 30, 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 September 30, 2016. (10) EBITDA calculated per bank loan covenant, which includes realized hedge settlements. Please see Appendix for calculation. EV/BOE(3,4,5)………………………... $8.98 Proved Reserves(8).…………..... 43.2 mmboe PV-10(8)……………………………….. $197.3 mm NBV Non-Oil & Gas Assets(9).. $22.3 mm Production(6).……………………… 5,955 boepd R/P Ratio(7)…………………………. 19.9x NASDAQ: AXAS Corporate Profile

4 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 South Texas Permian Basin Legend Proved Reserves (mmboe)(1): 43.2  Proved Developed(1): 32%  Oil(1): 56%  Current Prod (boe/d) (2): 5,955 Abraxas Petroleum Corporation Core Regions (1) Net proved reserves as of December 31, 2015. (2) Average production for quarter end September 30, 2016 2016 Capex Focus Areas

5 Area Capital ($MM) % of Total Gross Wells Net Wells Permian - Delaware $11.0 18.3% 2.0 2.0 Austin Chalk 10.5 17.5% 2.0 2.0 Bakken 36.8 61.3% 8.0 5.0 Other 1.7 2.8% Total $60.0 100% 12.0 9.0 2017 Operating and Financial Guidance 2017 Capex Budget Allocation 2017 Operating Guidance Operating Costs Low Case High Case LOE ($/BOE) $6.00 $8.00 Production Tax (% Rev) 9.0% 11.0% Cash G&A ($mm) $9.0 $11.0 Production (boepd) 7,000 7,400 (1) Yearly CAPEX for each year ending December 31, 2012, 2013, 2014 and 2015. 2016 and 2017 based on management guidance. (2) 2016 and 2017 estimates assume the midpoint of 2016 and 2017 guidance. $0 $50,000 $100,000 $150,000 $200,000 $250,000 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 20 12 A 20 13 A 20 14 A 20 15 A 20 16 E (2 ) 20 17 E (2 ) Ye ar ly C A P EX ( $M ) (B O EP D ) Daily Production vs Yearly CAPEX (1) Oil Gas NGL Oil 66% Natural Gas 21% 2017 Expected Production Mix NGL 13%

6 Upcoming Catalysts

7 Catalyst #1 Bakken / Three Forks  3,902 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 ▫ 1 non-operated well waiting on completion ▫ Expected to be on production 1Q17 ▫ 56 additional operated wells at 660-1320 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 currently drilling ▫ Anticipated 64.2% net revenue interest (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.

8 Old Design  2400 bbls / 165k prop  30 BPM  Xlink gel New Design  3500 bbls / 185k prop  45 BPM  Ramped & diverted HCFR Bakken / Three Forks Stenehjem 10H-15H Completion

9 Bakken / Three Forks North Fork Economics Middle Bakken: ROR vs CAPEX (1) (1) Uses strip pricing as of October 5, 2016. Abraxas Booked Assumptions  533 MBOE gross type curve ▫ 78% Oil ▫ Initial rate: 715 bopd ▫ di: 99.3% ▫ dm: 8.0% ▫ b-factor: 1.5  Booked CWC: $7.25 million Middle Bakken: Type Curve Assumptions Abraxas Updated Assumptions  728 MBOE gross type curve ▫ 78% Oil ▫ Initial rate: 930 bopd ▫ di: 98.5% ▫ dm: 8.0% ▫ b-factor: 1.3  CWC: ~$6.0 million

10 Catalyst #2 Permian Basin – Wolfcamp & Bone Spring – Ward/Reeves  5,811 net HBP acres located on the eastern edge of the Delaware Basin in Reeves/Ward/Pecos County (Pecos not shown) ▫ Four identified potential zones (Bone Spring, Wolfcamp)  Potential gross locations ▫ Caprito: 5 target intervals, 16 locations for each; 80 laterals ▫ BLK 16: 4 target intervals, 2 locations for each; 8 laterals ▫ GT Hall: 5 target intervals; 3 locations on strike for 3, 2 locations for 2; 13 laterals ▫ Fee 57: 4 target intervals; 4 locations; 16 laterals ▫ Howe: 3 target laterals; 12 locations; 36 laterals ▫ Fidelity Tr: 3 target intervals; 2 location; 6 laterals ▫ John May (Pecos County, not shown): 4 locations; 4 laterals  $5.5 million D&C costs for 5,000’ laterals  Wolfcamp A2 targeted EURs of ~500 mboe  First well – Caprito 99-101H – Wolfcamp A2 – on production  Next locations – Caprito 98-201H & Caprito 98-301H ▫ Spud January, 2017 ▫ Caprito 201H –target window Wolfcamp A1 “wine rack” spacing ▫ Caprito 301H – target window Wolfcamp A2 (same as 98-101H)  Exploring additional opportunities to expand position

11 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 Recently drilled

12 Wolfcamp Caprito 99-101H Completion Design Completion Design Stages: 25 Total Prop: 10.5mm lb (2400 lbs/ft) Total Fluid: 358,000 bbls (80 bbls/ft) Avg PPA: 0.71 ppg Avg Rate: 80 BPM Diversions: 52 Treating Plot Example

13 First 2 AC wells  7,642 total net acres located in the Jourdanton Field perspective for the Austin Chalk in Atascosa County, TX  $5.25 million D&C costs for 5,000’ laterals  2017 Capex plans call for drilling 2 net (2 gross) 5,000+’ lateral well for total cost of $5.25 million each  Fist well, Bulls Eye 101H ▫ 5,865’ effective lateral ▫ On production  Abraxas continues to evaluate acreage at terms that will ensure acceptable full cycle economics Catalyst #3 Austin Chalk

14 Catalyst #4 Potential Asset Sales (1) Inclusive of proceeds expected from Hudgins Ranch Sale of $6.7 million and Brooks Draw of $11.3 million. (2) Average for the month of June, 2016 2016 to date, Abraxas has monetized or has under contract approximately $35.5 million(1) 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 (2)  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 (2)  PSA signed Portilla  Large inventory conventional targets; EOR potential  Avg production ~150 boepd, ~87% oil (2)  No capital budgeted for 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;  Preparing to market Sinton office

15 Abraxas Hedging Profile (1) Straight line average price. Q4 2016 2017 2018 2019 Oil Swaps (bbls/day) 2500 2401 1796 1200 NYMEX WTI (1) $43.25 $54.53 $47.48 $54.54

16 Appendix

17 Abraxas’ Eagle Ford Properties ~11,109 Net Acres Jourdanton Area  Atascosa County  Black oil  7,642 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

18 Eagle Ford Jourdanton Jourdanton  7,642 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

19 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.

20 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.

21 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.

22 Powder River Basin Turner Sandstone Horizontal Play Porcupine Area: Turner Sandstone • 2,088 net acres (100% HBP) in an active area of Campbell and Converse counties • 30% state / 70% federal • Current producing wells: 5 (3 operated) (avg. operated WI / NRI: 100% / 83%) • Average net production(1): 121 Boe/d (29% liquids) Powder River Basin: Other Areas (not shown) • 1,895 net acres (100% HBP) • 49% federal / 51% fee • Primary targets: Turner, Parkman, Teapot, Muddy (1) August, 2016 average production.

23 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  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

24 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.

25 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

26 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) 31-Dec-15 31-Mar-16 30-Jun-16 30-Sep-16 TTM Net income ($67,661) ($40,880) ($46,937) ($3,260) ($158,738) Net interest expense 983 1,103 1,015 850 3,951 Income tax expense (37) 0 0 0 (37) Depreciation, depletion and amortization 7,677 5,892 5,669 6,371 25,608 Amortization of deferred financing fees 162 164 448 151 925 Stock-based compensation 826 807 835 768 3,237 Impairment 68,682 35,085 28,735 3,806 136,308 Unrealized (gain) loss on derivative contracts (3,608) 4,642 12,374 (3,484) 9,925 Realized (Gain) loss on interest derivative contract 0 0 0 0 0 Realized (Gain) loss on monetized derivative contracts 0 4,360 10,010 0 14,370 Earnings from equity method investment 0 0 0 0 0 (Gain) loss on discontinued operations 0 0 0 0 0 Expenses incurred with offerings and execution of loan agreement 0 0 1,665 82 1,747 Other non-cash items 457 583 36 (264) 813 EBITDA $7,480 $11,756 $13,851 $5,021 $38,108 Credit facility borrowings $90,000 Debt/EBITDA 2.36x

27 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

28 NASDAQ: AXAS