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Abraxas Petroleum
Corporate Update
January 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)……......... 160 mm
Market cap(2) …………………….... $401.9 mm
Net debt(2)……………………………. $33.0 mm
2017E CAPEX……………………….. $110 mm
(1) Abraxas full time employees as of October 12, 2016. Does not include 25 employees associated with the Company’s wholly owned subsidiary, Raven Drilling.
(2) Pro forma for $57.0 in estimated net proceeds to be received from recent 25 million share offering . Shares outstanding as of September 30, 2016 plus 25 million share offering. Market cap using share price as of January
22, 2017 close. Total debt including RBL facility, rig loan and building mortgage less cash as of January 22, 201 7.
(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 January 16, 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)…………………………… $10.32
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 ~$29 million(3) represents the only meaningful leverage (2, 3) of the Company and is
funded under recently re-determined $115 million revolving credit facility
Liquidity of ~$86 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 $5.0 million of debt associated with a rig loan and building mortgage.
(3) Pro forma for anticipated ~$57 million of net offering proceeds from recent 25 million share offering.
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
▫ Spud February, 2017
▫ 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
▫ 28-36% working 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.
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
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
Preparing to market 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