Abraxas Petroleum Corporate Update February 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, 2015 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)............................ 85 Shares outstanding(2)……......... 163.9 mm Market cap(2) …………………….... $404.8 mm Net debt(2)……………………………. $22.8 mm 2017E CAPEX……………………….. $110 mm (1) Abraxas full time employees as of January 31, 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 January 31, 2017 close. Total debt including RBL facility, rig loan 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 September 30, 2016, but does not include building mortgage or rig loan. Includes RBL facility, rig loan and building mortgage less cash as of February 1, 2017. (4) Proved reserves as of December 31, 2015. Uses SEC YE2015 average pricing of $41.25/bbl and $2.36/mcf. See appendix for reconciliation of PV-10 to standardized measure. (5) Net book value of other assets 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. EV/BOE(2,3)…………………………… $10.07 Proved Reserves(4)………………. . 43.2 mmboe PV-10(4)………………………………… $197.3 mm NBV Non-Oil & Gas Assets(5)… $22.3 mm Production(6).……………………….. 5,955 boepd R/P Ratio(7)…………………………… 19.9x NASDAQ: AXAS Corporate Profile
4 Williston: Bakken / Three Forks Eastern Shelf: Conventional & Emerging Hz Oil Eagle Ford Shale / Austin Chalk Delaware Basin: Bone Spring & Wolfcamp Rocky Mountain South Texas Permian Basin Legend Proved Reserves (mmboe)(1): 43.2 Proved Developed: 40% Oil: 56% Current Prod (boe/d) (2): 5,955 Abraxas Petroleum Corporation Core Regions (1) Net proved reserves as of December 31, 2015. (2) Average production for quarter ended September 30, 2016 2017 Capex Focus Areas
5 Area Capital ($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 and 2015. 2016 and 2017 based on management guidance. (2) 2016 and 2017 estimates assume the midpoint of 2016 and 2017 guidance. 66% 22% 12% 2017 Expected Production Mix Oil Gas NGL $0 $50,000 $100,000 $150,000 $200,000 $250,000 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 2 0 12 A 2 0 13 A 2 0 14 A 2 0 15 A 2 0 16 E (3 ) 2 0 17 E (3 ) Daily Production vs Yearly CAPEX (2)
6 Key Investment Highlights Continue to evaluate Austin Chalk and add cost-effective leases in geologically specific areas First well confirmed geologic concept Two well program in 2017 designed to establish economic viability via engineering and geologic modifications Austin Chalk 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 32% YoY production growth using the midpoints of 2016 and 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. (2) Company also has $4.0 million of debt associated with a rig loan and building mortgage. (3) As of February 1, 2017. 5,853(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 5,882 (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 99-101H – Wolfcamp A2 ▫ 30-Day IP Rate: 997 Boepd ▫ Significantly exceeding type curve to date Next locations – Caprito 98-201H & Caprito 98-301H ▫ Rigging up ▫ Caprito 201H –target window Wolfcamp A1 “wine rack” spacing ▫ Caprito 301H – target window Wolfcamp A2 (same as 99-101H) 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 Wolfcamp Caprito 99-101H Completion Design Completion Design Stages: 25 Total Prop: 10.5mm lb (2,400 lbs/ft) Total Fluid: 358,000 bbls (80 bbls/ft) Avg PPA: 0.71 ppg Avg Rate: 80 BPM Diversions: 52 Treating Plot Example
10 Delaware Wolfcamp Wolfcamp A2 Well Economics Wolfcamp: ROR vs CAPEX (1) (1) Uses strip pricing as of Jan 3, 2017. Abraxas Booked Assumptions 588 MBOE gross type curve ▫ 82% Oil ▫ Initial rate: 793 boepd ▫ di: 99.0% ▫ dm: 5.0% ▫ b-factor: 1.4 Booked CWC: $5.6 million Wolfcamp: Type Curve Assumptions Abraxas Updated Assumptions 650 MBOE gross type curve ▫ 92% Oil ▫ Initial rate: 1225 boepd ▫ di: 99.9% ▫ dm: 5.0% ▫ b-factor: 1.6 CWC: $5.6 million
11 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 ▫ 1 non-operated well waiting on completion ▫ Expected to be on production 1Q17 ▫ Estimated 56 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 currently drilling ▫ 62.0% 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.
12 Old Design 2,400 bbls / 165k prop 30 BPM Xlink gel New Design 3,500 bbls / 185k prop 45 BPM Ramped & diverted HCFR Bakken / Three Forks Stenehjem 10H-15H Completion
13 Bakken / Three Forks North Fork Economics Middle Bakken: ROR vs CAPEX (1) (1) Uses strip pricing as of January 3, 2017. Abraxas Booked Assumptions 533 MBOE gross type curve ▫ 78% Oil ▫ Initial rate: 910 boepd ▫ 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: 1183 boepd ▫ di: 98.5% ▫ dm: 8.0% ▫ b-factor: 1.5 CWC: ~$6.0 million
14 First 2 AC wells 7,685 total net acres located in the Jourdanton Field prospective for the 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 well, Bulls Eye 101H ▫ 5,865’ effective lateral ▫ 30-Day IP Rate: 366 Boepd ▫ Substantial production improvement post clean-out Abraxas continues to evaluate acreage at terms that will ensure acceptable full cycle economics Catalyst #3 Austin Chalk
15 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 (1) Sold January, 2017 Portilla Large inventory conventional targets; EOR potential Avg production ~150 boepd, ~87% oil (1) 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 Listing Sinton office Continuing to market Hudgins Ranch (Pecos County)
16 Appendix
17 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
18 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) 3 Months Ending 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 (Gai ) loss on dis ontinued operations (33,377) (1,318) 20 Expenses incurred with offerings and execution of loan agreement Other non-cash items 539 0 883 Adjusted EBITDA $44,663 $85,572 $43,957 Credit facility borrowings $33,000 $70,000 $134,000 Debt/ Adjusted EBITDA 0.74x 0.82x 3.05x
19 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-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 Expens s incurred with offerings and execution of loan agreement 0 0 1,665 82 1,747 Other non-cash items 457 583 36 (264) 813 Adjusted EBITDA $7,480 $11,756 $13,851 $5,021 $38,108 Credit facility borrowings $90,000 Debt/ Adjusted EBITDA 2.36x
20 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: As of December 31, 2015 Standariz d M asure (in thousands) 197,251 Present Value of f ture income taxas discounted at 10% (in thousands) - V-10 (in thousands) 197,251
21 NASDAQ: AXAS