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Abraxas Petroleum
Corporate Update
March 2018
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
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 $12.5
Production (boepd) 10,000 12,000
(1) Yearly CAPEX for each year ending December 31, 2013, 2014, 2015, 2016 and 2017. 2018 based on midpoint of management guidance.
(2) Average estimated production for 2018 based on the midpoint of management guidance.
66%
22%
12%
2018 Expected Production Mix
Oil Gas NGL
Area
Capital
($MM)
% of
Total
Gross
Wells
Net
Wells
Permian - Delaware $71.2 50.9% 12.0 9.0
Bakken/Three Forks 33.8 24.1% 10.0 4.7
Eagle Ford/Austin Chalk 0.0 0.0% 0.0 0.0
Acquisitions/Facilities/Other 35.0 25.0% 0.0 0.0
Total $140.0 100% 22.0 13.7
$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
A
20
18
E (
2)
Daily Production vs Yearly CAPEX (1)
4
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
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Bakken/Three Forks Wolfcamp
Abraxas D&C 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) $100mm $105mm $100mm
PDP (2)
Incremental Bakken/
Three Forks (2)
Incremental Third Bone
Spring/Wolfcamp (2)
B
ar
re
ls
o
f
Eq
u
iv
al
e
n
t
p
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r
D
ay
(
B
o
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p
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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 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 and $35 associated with acquisitions consummated or planned during 2017 and 2018, respectively.
5
9,223 net acres located in the eastern core of the Delaware Basin
Four proven potential zones (Bone Spring, Wolfcamp)
▫ 190+ gross operated identified potential locations
▫ 360+ gross operated identified potential locations with downspacing
▫ 100+ gross non-operated identified potential locations
2+ additional potential zones (Bone Spring, Wolfcamp)
Unique, legacy high value acreage
▫ Favorable net revenue interests – in many cases 1/8th royalty
▫ 95+% held by production
Infrastructure – Caprito Area
▫ Two water supply wells
▫ Two 400,000 bbl lined frac pits,
▫ SWD wells and system in place
▫ Full gas gathering system (third party operated)
▫ Oil gathering system under construction (Third Party
Exploring additional opportunities to expand position
Delaware Basin
Permian Basin – Wolfcamp & Bone Spring
Map Source: Callon, Jagged Peak, Halcon, Diamondback presentations, Drilling Info and management estimates.
6
Delaware Basin
Recent Acquisition – Wolfcamp & Bone Spring – Winkler County
Total of 944 net acres in Winkler County on trend with Abraxas
current leasehold position in Ward
560 operated / 384 non operated; two operated units
Four prospective zones across Wolfcamp/Bone Spring
Up to 32 gross operated locations
Up to 28 remaining gross non-operated locations
Includes two non-operated wells currently drilling at a 30%
working interest
Abraxas existing leasehold indicated in yellow
Acquisition leasehold indicated in purple
7
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 – producing
▫ Wolfcamp B – Caprito 83-404H – producing
Third Pad – Section 82 Pad – Two Well Pad
▫ Wolfcamp A1 – Caprito 82-202H – producing
▫ Third Bone Spring – Caprito 82-101H – producing
Fourth Pad – Section 99 Pad – Four Well Pad
▫ Wolfcamp A1 – Caprito 99-211H and 202H – downspacing test - WOC
▫ Wolfcamp A2 – Caprito 99-301H and 311H – downspacing test - drilling
8
1
2
3 4
5 6
7 8
9
10
11 12
13
14
16
17
18
19
15
20
21
9
Univ Lands Beldin 3H
Jagged Peak
IP24: 1,415 BOEPD (81% Oil)
LL: 9,561’
Surrounding Delaware Activity
2
Univ Lands Beldin 4H
Jagged Peak
LL: 10,000’
3 & 4
Caprito 82 101H (3BS) &
202H (WC A1)
Abraxas
101H IP30: 1,122 BOEPD
(78% Oil) LL: 4,820’
202H IP30: 1,134 BOEPD
(76% Oil) LL: 4,820’
5
Sealy Ranch 7902H
Halcon
IP30: 1,665 BOEPD
(80% Oil) LL: 9,267’
7 & 8
Caprito 83 304H (WC A2)
& 404 (WC B)
304H IP30: 1,014 BOEPD
(77% Oil) LL: 4,820’
404H IP30: 603 BOEPD
(84% Oil) LL: 4,820’
1
Sealy Ranch 9301H
Halcon
IP30: 1,489 BOEPD
(80% Oil) LL: 9,912’
10
Caprito 99 302H
Abraxas
IP: 997 BOEPD (83% Oil)
LL: 4,529’
13
CRMWD-79 1H
Halcon
IP30: 1,343 BOEPD
(80% Oil) LL: 5,305’
11
Caprito 98 301HR (WC A2)
Abraxas
IP30: 999 BOEPD
(84% Oil) LL: 4,880’
12
Caprito 98 201H (WC A1)
Abraxas
IP30: 1,036 BOEPD
(84% Oil) LL: 4,880’
17
State Whiskey River 4-8-2H
Jagged Peak
IP 24: 2,260 BOEPD
LL:10,000’
18 & 19
Sealy Ranch 7701H & 7703H
Halcon
LL: 10,000’
15
Whiskey River 7374A&B
Jagged Peak
IP24: 2,504 BOEPD
LL: 9,000’
14
St. Quadricorn 1617A 1H
Jagged Peak
Flowback Test: 1,500 BOEPD
LL: 10,000’
16
State 5913A 2H
Jagged Peak
IP24: 1,179 BOEPD (83% Oil)
LL: 6,662’ (Wolfcamp C)
20
UL Willow 3836-16 1H
Felix
LL: 10,000’
21
University Land 1H, 3H, & 4H
Felix
LL: 10,000’
6
Sealy Ranch 7903H
Halcon
IP30: 1,978 BOEPD
(83% Oil) LL: 9,781’
Delaware Basin
Third Bone Spring Well Economics
3RD Bone Spring: ROR vs WTI
Abraxas EOY17 Assumptions
660 MBOE gross type curve
▫ 84% Oil
▫ Initial rate: 1100 boepd
▫ di: 99.9%
▫ dm: 6.0%
▫ b-factor: 1.4
Assumed CWC: $7.3 million
3RD Bone Spring: Type Curve Assumptions
9
0
200
400
600
800
1000
1200
1400
0 20 40 60 80 100 120 140 160 180
B
O
E
DAYS
3rd BONE SPRING DAILY PRODUCTION (82 101H)
82 101H BOE (BS) 3RD BS BOE TYPE
Delaware Basin
Wolfcamp A1 Well Economics
Wolfcamp A1: ROR vs WTI
Abraxas EOY17 Assumptions
680 MBOE gross type curve
▫ 77% Oil
▫ Initial rate: 860 boepd
▫ di: 95.0%
▫ dm: 7.0%
▫ b-factor: 1.4
Assumed CWC: $7.3 million
Wolfcamp A1: Type Curve Assumptions
10
0
200
400
600
800
1000
1200
1400
0 20 40 60 80 100 120 140 160 180
B
O
E
DAYS
WOLFCAMP A1 AVERAGE DAILY PRODUCTION
A1 Wells BOE Average A1 BOE TYPE
Delaware Basin
Wolfcamp A2 Well Economics
Wolfcamp A2: ROR vs WTI
Abraxas EOY17 Assumptions
650 MBOE gross type curve
▫ 82% Oil
▫ Initial rate: 650 boepd
▫ di: 95.0%
▫ dm: 7.0%
▫ b-factor: 1.4
Assumed CWC: $7.3 million
Wolfcamp A2: Type Curve Assumptions
11
0
200
400
600
800
1000
1200
0 20 40 60 80 100 120 140 160 180
B
O
E
DAYS
WOLFCAMP A2 AVERAGE DAILY PRODUCTION
A2 Wells BOE Average A2 BOE TYPE
Delaware Basin
Wolfcamp B Well Economics
Wolfcamp B: ROR vs WTI
Abraxas EOY17 Assumptions
535 MBOE gross type curve
▫ 85% Oil
▫ Initial rate: 580 boepd
▫ di: 95.0%
▫ dm: 7.0%
▫ b-factor: 1.4
Assumed CWC: $7.3 million
Wolfcamp B: Type Curve Assumptions
12
0
100
200
300
400
500
600
700
800
0 20 40 60 80 100 120 140 160 180
B
O
E
DAYS
WOLFCAMP B DAILY PRODUCTION (83 404H)
393 B BOE TYPE
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
▫ 44 operated completed wells
▫ Est. 24 gross additional operated Bakken/ First Bench Three
Forks locations remaining
▫ Est. 20 gross additional Second Bench Three Forks locations
remaining
▫ 7 operated wells waiting on completion
▫ 4 operated wells drilling
▫ Est. 37 gross/3 net additional non-operated locations remaining
Yellowstone 2H-4HR
▫ 42.7% net revenue interest
▫ 30-day MB average rate(1) 1,777 boepd
▫ 30-day TF average rate(1) 1,371 boepd
Yellowstone 5H-7H
▫ Three well pad waiting on completion
▫ June frac date
▫ 42.7% net revenue interest
Lillibridge 9H-12H
▫ Four well pad waiting on completion
▫ June frac date
Ravin 9H-12H
▫ Four well pad preparing to spud
(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.
Middle Bakken
North Fork Economics
Middle Bakken: ROR vs WTI
Abraxas EOY17 Assumptions
845 MBOE gross type curve
▫ 76% Oil
▫ Initial rate: 1120 boepd
▫ di: 98.5%
▫ dm: 8.0%
▫ b-factor: 1.5
Assumed CWC: $7.0 million
Middle Bakken: Type Curve Assumptions
0
200
400
600
800
1,000
1,200
1,400
0 20 40 60 80 100 120 140 160 180
B
O
EP
D
DAYS
NORMALIZED AVERAGE PRODUCTION BY WELL GROUP
NORTH FORK FIELD - MIDDLE BAKKEN ONLY
GEN 1 COMPLETIONS; GEN 2 COMPLETIONS; GEN 3 COMPLETIONS; LINE = EOY16 TYPE
Three Forks
North Fork Economics
Three Forks: ROR vs WTI
Abraxas EOY17 Assumptions
723 MBOE gross type curve
▫ 73% Oil
▫ Initial rate: 1050 boepd
▫ di: 98.5%
▫ dm: 8.0%
▫ b-factor: 1.5
Assumed CWC: $7.0 million
Three Forks: Type Curve Assumptions
0
200
400
600
800
1000
1200
1400
0 20 40 60 80 100 120 140 160 180
B
O
EP
D
DAYS
NORMALIZED AVERAGE PRODUCTION BY WELL GROUP
NORTH FORK FIELD - THREE FORKS ONLY
GEN 1 COMPLETIONS; GEN 2 COMPLETIONS; GEN 3 COMPLETIONS; LINE=EOY16 TYPE
16
(1) 2018 daily volumes indicated for February – December 2018.
(2) Straight line average price. Includes 2,651 and 1,200 of WTI swaps in 2018 and 2019, respectively. Includes 500 Bopd and 1,000 Bopd of LLS swaps in 2018 and 2019, respectively.
Abraxas Hedging Profile
2018 (1) 2019 2020
Oil Swaps (bbls/day) 4,453 2,783 2,206
NYMEX (2) $53.74 $55.66 $54.34