Abraxas Petroleum
Corporate Update
September2017
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) …………………….... $305.3 mm
Net debt(2)……………………………. $34.1 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 August 15, 2017. Market cap using share price as of September 22, 2017. Total debt including RBL facility and building mortgage less cash as of June 30, 2017
(3) Enterprise value includes working capital deficit (excluding current hedging assets and liabilities) as of June 30, 2017, but does not include building mortgage. Includes RBL facility and building mortgage less cash as of June 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 June 30, 2017.
(6) Average production for the quarter ended June 30, 2017
(7) Calculation using average production for the quarter ended June 30, 2017 annualized and net proved reserves as of December 31, 2016.
EV/BOE(2,3)…………………………… $8.06
Proved Reserves(4)………………. . 44.7 mmboe
NBV Non-Oil & Gas Assets(5)… $21.7 mm
Production(6).……………………….. 5,172 boepd
R/P Ratio(7)…………………………… 23.7x
NASDAQ: AXAS
Corporate Profile
4
Williston:
Bakken / Three Forks
Eastern Shelf:
Conventional & Emerging Hz Oil
Eagle Ford Shale
/ Austin Chalk
Delaware Basin:
Bone Spring & Wolfcamp
Rocky Mountain
South Texas
Permian Basin
Legend
Proved Reserves (mmboe)(1): 44.7
Proved Developed: 31%
Oil: 54%
Current Prod (boepd) (2): 5,172
Abraxas Petroleum Corporation
Core Regions
(1) Net proved reserves as of December 31, 2016.
(2) Average production for quarter ended June 30, 2017
2017 Capex Focus Areas
5
Area
Capital
($MM)
% of
Total
Gross
Wells
Net
Wells
Permian - Delaware $71.3(1) 59.4% 7.0 6.0
Bakken/Three Forks 42.2 35.1% 13.0 6.6
Eagle Ford/Austin Chalk 6.0 5.0% 1.0 1.0
Other 0.5 0.4% 0.0 0.0
Total $120.0(1) 100% 21.0 13.6
2017 Operating and Financial Guidance
2017 Capex Budget Allocation 2017 Operating Guidance
Operating Costs
Low
Case
High
Case
LOE ($/BOE) $5.00 $7.00
Production Tax (% Rev) 8.0% 10.0%
Cash G&A ($mm) $11.0 $13.5
Production (boepd) 7,800 8,200
(1) Includes $110 million in cash and $10 million in shares and Abraxas’ Cayanosa Draw ranch used as consideration in July 2017 Ward County purchase.
(2) Yearly CAPEX for each year ending December 31, 2012, 2013, 2014, 2015 and 2016. 2017 based on management guidance; 2017 estimates assume the midpoint of 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
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 (1,2) 2017 Expected Production Mix
Oil Gas NGL
61%
23%
16%
6
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
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
CAPEX $120mm $90mm $90mm
PDP (2)
Incremental Bakken/
Three Forks (2)
Incremental
Wolfcamp (2)
Incremental Eagle
Ford/Austin Chalk (2)
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Eq
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D
ay
(
B
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(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 perm its 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.
7
Key Investment Highlights
Continue to evaluate Eagle Ford/Austin Chalk
First well confirmed Austin Chalk geologic concept
One well program in 2017 designed to establish economic viability of the Eagle Ford via drilling and
completion modifications
Austin Chalk/ Eagle Ford
Optionality
Total bank debt of ~$31 million(3) represents the only meaningful leverage (2, 3) of the Company and is
funded under the $115 million revolving credit facility
Liquidity of ~$84 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 net) operated Wolfcamp/Bone Spring wells planned for 2017
13 gross (7 net) operated and non-operated Bakken/Three Forks wells planned for 2017
Total Capex of $120 million funded out of cash flow and RBL provides 29% 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.
(2) Company also has $3.8 million of debt associated with a building mortgage.
(3) As of June 30, 2017.
8,368 (1) net HBP acres prospective for the Wolfcamp A, B & Bone Spring intervals
Plan to test multiple prospective zones in 2017
Continue to actively lease and pursue acquisitions – recent acquisitions of 2,500+ net acres
Allocated 2017 capital budget of $71MM (59% of total allocation)
Delaware Basin Exposure
8
Asset Base Overview
9
8,368 (1) net HBP acres located in the eastern core of the Delaware Basin
▫ Up to five identified potential zones (Bone Spring, Wolfcamp)
Favorable net revenue interests
Wolfcamp A2 targeted EURs of ~604 mboe
Caprito 98-201H – Wolfcamp A1
▫ 30-Day IP Rate: 1,036 Boepd
▫ Exceeding type curve to date
Caprito 98-301HR – Wolfcamp A2
▫ 30-Day IP Rate: 999 Boepd
▫ Exceeding type curve to date
Caprito 83-304H (A2) & Caprito 83-404H (B)
▫ Caprito 83-304H – Wolfcamp A2
▫ Caprito 83-404H – Wolfcamp B
▫ Completing
Caprito 82-202H (A1) & Caprito 82-101H (3BS)
▫ Caprito 82-202H – Wolfcamp A1 – Drilling
▫ Caprito 83-101H – Third Bone Spring – Drilling
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.
Delaware Basin
Permian Basin – Wolfcamp & Bone Spring – Ward/Reeves
10
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 – completing
▫ Wolfcamp B – Caprito 83-404H – completing
Third Pad – Section 82 Pad – Two Well Pad
▫ Wolfcamp A1 – Caprito 82-202H – drilling
▫ Third Bone Spring – Caprito 82-101H – drilling
Fourth Pad – Section 99 Pad – Four Well Pad
▫ Wolfcamp A1 – 2 wells – downspacing test
▫ Wolfcamp A2 – 2 wells – downspacing test
Results Will Dictate Future Development of Each Interval on
Subsequent Pads
11
Delaware Basin
Downspacing Example
Phantom Field Spacing
▫ 1320’ between wells same zone
▫ 660’ downspacing potential
▫ Pattern repeats for additional targets
Drilling Targets include 4 benches
▫ 3rd Bone Spring
▫ Upper Wolfcamp A1
▫ Upper Wolfcamp A2
▫ Wolfcamp B
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
Booked CWC: $6.0 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 35 additional operated wells
▫ Estimated 36 gross/3 net additional non-operated locations
▫ 3 operated wells waiting on completion
▫ 3 operated wells drilling
▫ 4 non-operated wells completed/completing
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 flowing back
▫ 62.0% net revenue interest
▫ More conservative flowback
▫ 30-day MB average rate(1) 1,148 boepd
▫ 30-day TF average rate(1) 1,143 boepd
Yellowstone 2H-4HR
▫ Three well pad waiting on completion
▫ 42.7% 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.
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
Middle Bakken
North Fork Economics
Middle Bakken: ROR vs WTI 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
15
LATEST WELLS
Three Forks
North Fork Economics
Three Forks: ROR vs WTI 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
16
LATEST WELLS
Three Forks
Cum Oil vs. Pressure Performance
Three Forks: Type Curve Assumptions
17
18
Shut Eye 1H
9,360 net acres located in Atascosa
County, TX prospective for the Eagle
Ford and Austin Chalk
2017 Capex plans call for drilling 1
net 6,700’ lateral well and leasing
Shut Eye 1H – EF Test
▫ Drilled, cased and waiting on
completion
▫ Enhanced completion design
Jourdanton
Eagle Ford/Austin Chalk
19
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
20
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 $40.1 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 -
Other
Stacked pay, liquids-rich horizontal
opportunities primarily in Campbell
County, Wyoming
~947 net high value acres at
Porcupine/Frazier Federal
Marketing
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
1,141 net acres at Porcupine
~128 bopd net production
Brooks Draw Sold January 2017
Portion of Porcupine and “other”
acres Sold July 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
21
Appendix
22
(1) Straight line average price.
Abraxas Hedging Profile
3Q17 4Q17 2018 2019
Oil Swaps (bbls/day) 2,417 4,063 2,651 1,200
NYMEX WTI (1) $54.60 $52.82 $48.53 $54.54
WTI Midland / WTI CMA (bbls/day) 500 500
Differential ($/bbl) ($0.65) ($0.65)
Henry Hub Costless Collar (mmbtu/day) 5,000 5,000
Ceiling ($/mmbtu) $3.90 $3.90
Floor ($/mmbtu) $3.00 $3.00
23
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
24
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)
30-Sep-16 31-Dec-16 31-Mar-17 30-Jun-17 TTM
Net income ($3,260) ($5,302) $13,691 $7,194 $12,324
Net interest expense 850 859 395 389 $2,493
Income tax expense 0 0 0 0 $0
Depreciation, depletion and amortization 6,371 6,500 5,374 4,415 $22,659
Amortization of deferred financing fees 151 256 138 116 $661
Stock-based compensation 768 784 770 979 $3,300
Impairment 3,806 0 0 0 $3,806
Unrealized (gain) loss on derivative contracts (3,484) 6,285 (8,760) (5,071) ($11,031)
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
(Gain) loss on discontinued operations 0 0 0 0 $0
Expenses incurred with offerings and execution of loan agreement 82 0 3,790 703 $4,575
Other non-cash items 111 139 112 113 $474
EBITDA $5,395 $9,521 $15,507 $8,838 $39,262
Credit facility borrowings $31,250
Debt/EBITDA 0.80x
25
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
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NASDAQ: AXAS