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Abraxas Petroleum Corporate Update
August 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
I. Abraxas Petroleum Overview
4
Headquarters.......................... San Antonio
Employees(1)............................ 89
Shares outstanding(2)……......... 135.1 mm
Market cap(4) …………………….... $152.6 mm
Net debt(3)………………………….. $98.0 mm
2016E CAPEX………………………. $40 mm
(1) As of May 25, 2016. Does not include nine employees associated with the Company’s wholly owned subsidiary, Raven Drilling.
(2) Shares outstanding as of May 25, 2016.
(3) Total debt including RBL facility, rig loan and building mortgage less cash as of May 25, 2016.
(4) Share price as of May 31, 2016.
(5) Enterprise value includes working capital deficit (excluding current hedging assets and liabilities) as of May 25, 2016, but does not include building mortgage or rig loan. Includes RBL facility, rig loan and building mortgage less cash as of May 25, 2016.
(6) Average production for the quarter ended March 31, 2016.
(7) Calculation using average production for the quarter ended March 31, 2016 annualized and net proved reserves as of December 3 1, 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 March 31, 2016.
EV/BOE(3,4,5)………………………... $5.91
Proved Reserves(8).…………..... 43.2 mmboe
PV-10(8)……………………………….. $197.3
mm
NBV Non-Oil & Gas Assets(9).. $26.9 mm
Production(6).……………………… 5,916 boepd
R/P Ratio(7)…………………………. 20.0x
NASDAQ: AXAS
Corporate Profile
5
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
Gulf Coast
Permian Basin
Legend
Proved Reserves (mmboe)(1): 43.2
Proved Developed(1): 32%
Oil(1): 56%
Current Prod (boe/d) (2): 5,916
Abraxas Petroleum Corporation
Core Regions
(1) Net proved reserves as of December 31, 2015.
(2) Average production for quarter end March 31, 2016
2016 Capex Focus Areas
6
Key Investment Highlights
5,227 net HBP acres prospective for the Wolfcamp A & Bone Spring intervals
Recent Wolfcamp A & Bone Spring offset results demonstrate +1,500 boe/d 24-hour average rates
Plan to drill two 5,000 ft. Wolfcamp A laterals in 2016 with first well to spud in August 8, 2016
TD’d first 5,865 ft. effective lateral Austin Chalk well test; completion scheduled for August 19, 2016
Emerging Delaware Basin
and Austin Chalk Exposure
Total bank debt of $93 million (2) represents the only meaningful leverage (1, 2) of the company and is
funded under recently re-determined $130 million revolving credit facility
Company is positioned to meet all of its covenant calculations for the long term
Liquidity of ~$38 million (2) positions the company to take advantage of distressed sellers
Actively looking to consolidate Delaware basin working interest position
Management continues to pursue and execute on non-core asset sales
Balance Sheet Positioned for
the Downturn with Solid
Liquidity & Financial
Flexibility
6 gross (4.7 net) operated Bakken/Three Forks wells currently completing at the Stenehjem pad
provide confidence in production guidance for FY:2016
Total Capex of $30-40 million funded out of cash flow and offering proceeds provides 4% YoY
production growth at the midpoint of the 2016 guidance range
Visible Production Growth and
Fully Funded Capex Program
Seasoned and Aligned
Executive Management
Team
CEO has been at the helm for ~40 years and has navigated numerous downturns
Management and affiliates own ~10% of the company
(1) Company has $5.8 million of debt associated with a rig loan and building mortgage.
(2) As of May 25, 2016.
7
Area
Capital
($MM)
% of
Total
Gross
Wells
Net
Wells
Permian - Delaware $10.0 25.0% 2.0 1.0
Austin Chalk 5.7 14.3% 1.0 1.0
Bakken 12.0 30.0% 7.0 5.0
Other 12.3 30.8%
Total $40.0 100% 10.0 7.0
2016 Operating and Financial Guidance
2016 Capex Budget Allocation 2016 Operating Guidance
Operating Costs
Low
Case
High
Case
LOE ($/BOE) $8.0 $10.5
Production Tax (% Rev) 9.0% 12.0%
Cash G&A ($mm) $8.0 $12.0
Production (boepd) 6,000 6,400
(1) Yearly CAPEX for each year ending December 31, 2011, 2012, 2013, 2014 and 2015. 2016 represents the midpoint of guidance.
(2) 2016 estimate assumes the midpoint of 2016 guidance of 6,000 – 6,400 boepd.
(Boep
d)
Daily Production vs Yearly CAPEX(1)
Ye
arl
y C
ap
ex
($
M)
3,484
3,937
4,298
5,720
5,975
6,200
$0
$50,000
$100,000
$150,000
$200,000
$250,000
0
1,00
2,000
3,000
4,000
5,000
6,000
7,000
20
11
A
20
12
A
20
13
A
20
14
A
20
15
A
20
16
E (
2)
8
Asset Base Overview
9
Abraxas Delaware Basin Assets
Wolfcamp & Bone Spring Potential
5,227 net HBP acres located on the eastern edge of the
Delaware Basin in Reeves/Ward County
▫ 42 gross / 27 net geologically risked potential horizontal
locations
▫ Assumes one prospective zone (Third Bone Spring/Wolfcamp A)
Prospective for the Wolfcamp and Bone Spring intervals
▫ Average thickness for both sections ranges from 300’ – 500’
Offset operator 24-hour IP’s up to 1,700 Boe/d (~84% oil)
$5.95 million D&C costs for 5,000’ laterals
Targeted EURs of ~500 mboe
2016 Capex plans call for drilling 1 net (2 gross) well and
additional acquisitions and leasing for total cost of $10
million
First well to spud August 8, 2016
Multiple offers made to consolidate working interests in units
Exploring additional opportunities to expand position
10
Wolfcamp Overpressure
Well along strike to
AXAS leases
Luo et al 1994
A
A’
A A’
Contours are amount of overpressure
in MPa (10 MPa = 1450 psi)
11
3rd Bone Spring and Wolfcamp A thickness
similar to basinal wells
Horizontals target top of Wolfcamp
Lower Wolfcamp interval much thicker in
basin
3rd Bone Spring and Wolfcamp
Comparison of Abraxas Leases to WC/BS Horizontal Activity
Target
12
3rd Bone Spring and Wolfcamp
Abraxas Lease Areas:
3rd Bone Spring and
Wolfcamp A present,
relatively consistent
Lower Wolfcamp and
underlying Penn. interval,
variable
13
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
Recent Permits
14
Strong Offset Operator Results
Abraxas’ acreage is located on the eastern platform of
the play
Jagged Peak has been the most active operator in the
area to date achieving attractive results in both the
Wolfcamp and Bone Spring
▫ 3 month cum avg: 56,000 boe
▫ 6 month cum avg: 90,000 boe
Jagged Peak Ten Well Cum Results(1)
Pyote Flats
Whiskey River 98-34
Eiland
Trinity 15-33 1H (Bone Spring)
Whiskey River 1H
Cilantro
Whiskey River 2H
(1) Jagged Peak cumulative production data from the Texas Railroad Commission / HPDI.
15
Bakken / Three Forks
North Fork/Lillibridge Potential
3,902 net HBP acres located in the core of the Williston Basin
in Mckenzie County, ND – de-risked Bakken and Three Forks
▫ 30 operated completed wells
▫ 6 operated wells completing
▫ Expected to bring on production mid-August 2016
▫ 1 non-operated well waiting on completion
▫ Expected to bring on production 1Q17
▫ 9 planned multi-well pads at 660 ft. spacing
▫ 60 additional operated wells at 660-1320 foot spacing
▫ Additional upside potential from 3rd bench of the Three Forks
Average 30-day IPs of 999 Boe/d on last 25 wells drilled
2016 Capex plans call for the completion of 5.0 net (7.0 gross)
wells for total cost of $12.0 million
16
Well Objective Lat. Length (1) Stages (1) 30-day IP (boepd) (1,2) Status
Ravin 1H Three Forks 10,000 23 391 Producing
Stenehjem 1H Middle Bakken 6,000 17 688 Producing
Jore Federal 3H Three Forks 10,000 35 510 Producing
Ravin 26-35 2H , 3H Middle Bakken 10,000 16 524 Producing
Lillibridge 2H, 4H Three Forks 9,000 28 940 Producing
Lillibridge 1H, 3H Middle Bakken 10,000 33 1,283 Producing
Lillibridge 6H, 8H Three Forks 10,000 33 971 Producing
Lillibridge 5H, 7H Middle Bakken 10,000 34 1,027 Producing
Jore 1H Three Forks 10,000 33 1,037 Producing
Jore 2H, 4H Middle Bakken 10,000 33 904 Producing
Ravin 4H, 5H, 6H, 7H Middle Bakken 10,000 33 1,254 Producing, first MB downspacing test
Stenehjem 2H, 4H Three Forks 10,000 33 863 Producing, first TF downspacing test
Stenehjem 3H Middle Bakken 10,000 33 1,057 Producing
Jore 5H, 6H, 7H, 8H Middle Bakken 10,000 33 819 Producing
Stenehjem 5H Middle Bakken 10,000 33 809 Producing
Sten-Ravin 1H, Ravin 8H Three Forks 10,000 33 900 Producing
Stenehjem 10H, 12H, 14H Three Forks 10,000 NA NA Completing
Stenehjem 11H, 13H, 15H Middle Bakken 10,000 NA NA Completing
Bakken / Three Forks
Focused on Execution
(1) Represents the approximate, average lateral length, number of stages and 30-day IP for each group of wells.
(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.
17
Bakken / Three Forks
Exceptional Well Performance versus Type Curve
12/31/14 Type Curve = 420 MBO/well
12/31/15 Type Curve = 440 MBO/well
18
Austin Chalk
Jourdanton
First 2 AC wells
7,776 total net acres located in the
Jourdanton Field perspective for the
Austin Chalk in Atascosa County, TX
▫ 90+ wells of Austin Chalk potential
$5.0 million D&C costs for 5,000’
laterals
Targeted EURs of ~400 mbo for 5,000’
lateral
2016 Capex plans call for drilling 1
net (1 gross) 5,700’ lateral well for
total cost of $5.7 million
Fist well, Bulls Eye 101H
▫ Successfully TD’d 5,865’ effective
lateral
▫ Completion scheduled August 18,
2016
19
Atascosa Trough
Vertical Chalk Production (Cumulative Oil)
Jourdanton Lease Block
Karnes Trough
Atascosa Trough
20
Karnes Trough
Vertical and Horizontal Austin Chalk Production (Cumulative Oil)
Blackbrush
Kolodziej-Pawelek Unit 102H
CUM Production
Oil: 208 MBO
Gas: 389 MMCF
7 Months
EOG Leonard AC Unit 101H
30-Day IP: 2,100 Bopd
and 2,715 Boepd
CUM Production
Oil: 65 MBO
Gas: 87MMCF
1 Month
Blackbrush
Annie Trail/Yanta
11 – 14 Months
21
Key Investment Highlights
5,227 net HBP acres prospective for the Wolfcamp A & Bone Spring intervals
Recent Wolfcamp A & Bone Spring offset results demonstrate +1,500 boe/d 24-hour average rates
Plan to drill two 5,000 ft. Wolfcamp A laterals in 2016 with first well to spud in August 8, 2016
TD’d first 5,865 ft. effective lateral Austin Chalk well test; completion scheduled for August 19, 2016
Emerging Delaware Basin
and Austin Chalk Exposure
Total bank debt of $93 million (2) represents the only meaningful leverage (1, 2) of the company and is
funded under recently re-determined $130 million revolving credit facility
Company is positioned to meet all of its covenant calculations for the long term
Liquidity of ~$38 million (2) positions the company to take advantage of distressed sellers
Actively looking to consolidate Delaware basin working interest position
Management continues to pursue and execute on non-core asset sales
Balance Sheet Positioned for
the Downturn with Solid
Liquidity & Financial
Flexibility
6 gross (4.7 net) operated Bakken/Three Forks wells currently completing at the Stenehjem pad
provide confidence in production guidance for FY:2016
Total Capex of $30-40 million funded out of cash flow and offering proceeds provides 4% YoY
production growth at the midpoint of the 2016 guidance range
Visible Production Growth and
Fully Funded Capex Program
Seasoned and Aligned
Executive Management
Team
CEO has been at the helm for ~40 years and has navigated numerous downturns
Management and affiliates own ~10% of the company
(1) Company has $5.8 million of debt associated with a rig loan and building mortgage.
(2) As of May 25, 2016.
22
Appendix
23
Additional Assets
Opportunity Overview Abraxas Assets 2016 Development
Powder
River Basin
Stacked pay, l iquids-rich horizontal
opportunities in Campbell,
Converse and Niobrara Counties,
Wyoming
Primarily in Converse and Campbell counties
Appx 2,088 net acres at Porcupine and
14,245 net acres at Brooks Draw
Hedgehog State 16-2H: Cum prod. (38 mos):
366 mboe, 23% Oil
No capital budgeted for 2016
Other
Permian
Basin
Large inventory conventional and
unconventional targets
Emerging, oil -focused horizontal
dril l ing opportunities
28,370 total net acres
Average production 856 boepd, ~23% oil (1)
No capital budgeted for 2016
Raven
Drilling
Abraxas 100% wholly owned
subsidiary
$15.8 mill ion in NBV secured
against $1.9 mill ion in rig debt (2)
One 2,000 horsepower, SCR walking rig
currently pad dril l ing in the Bakken
Subsidiary includes man camp and
additional related rig equipment
No capital budgeted for 2016
Surface /
Yards / Field
Offices /
Building
Surface ownership in numerous
legacy areas
Net book value of $11.2 mill ion (3)
Surface : 610 acres Scurry, TX; 1,769 acres in
San Patricio, TX; 12,178 acres Pecos, TX; 590
acres McKenzie, ND; 50 acres DeWitt, TX; 15
acres Atascosa, TX
Yards/Offices/Structures: Sinton, TX; Scurry,
Texas; McKenzie, ND;
21,000 square foot office building
No capital budgeted for 2016
(1) Average for month of December 31, 2015
(2) As of March 31, 2016
(3) As of December 31, 2015
24
Abraxas’ Eagle Ford Properties
~10,819 Net Acres
Jourdanton Area
Atascosa County
Black oil
7,352 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
25
Eagle Ford
Jourdanton
Jourdanton
7,352 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
26
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.
27
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.
28
Well Area Lat. Length (1) Stages (1) 30-day IP (boepd) Status
T-Bi rd 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 Di lworth East 5,000 19 780 (2) Producing
R. Henry 1H Di lworth 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.
29
Powder River Basin
Turner Sandstone Horizontal Play
Powder River Basin: Turner Sandstone
Isopach of Turner thickness
Multiple producing vertical wells, tight sandstone
Horizontal exploitation with multi-stage fracs
recently
Porcupine Area
▫ Approximately 2,088 net acres
Brooks Draw Area
▫ Approximately 14,245 net acres
30
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
Permian, Hudgins Ranch: 3 gross / 2.6 net PSUD locations, 9.1 bcfe (net) (4)
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
31
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.
32
Abraxas Hedging Profile
(1) Straight line average price.
Q2 2016 Q3 2016 Q4 2016 2017 2018
Oil Swaps (bbls/day) 1948 1948 2500 1908 1500
NYMEX WTI (1) $39.04 $39.04 $43.25 $55.39 $46.39
33
EBITDA Reconciliation
EBITDA is defined as net income plus interest expense, depreciation, depletion and amortization expenses, deferred income tax es 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
Earni gs 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
34
TTM EBITDA Reconciliation
EBITDA is defined as net income plus interest expense, depreciation, depletion and amortization expenses, deferred income tax es 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) Three Months End
31-Mar-15 30-Jun-15 30-Sep-15 31-Dec-15 TTM
Net income $7,407 ($6,429) ($52,372) ($67,661) ($119,055)
Net interest expense 694 816 847 983 3,340
Income tax expense 0 0 0 (37) (37)
Depreciation, depletion and amortization 12,069 8,637 10,165 7,677 38,548
Amortization of deferred financing fees 644 162 162 162 1,130
Stock-based compensation 810 1,440 835 826 3,912
Impairment 0 0 59,891 68,682 128,573
Unrealized (gain) loss on derivative contracts (9,806) 5,470 (10,474) (3,608) (18,417)
Realized (Gain) loss on interest derivative contract 0 0 0 0 0
Realized (Gain) loss on monetized derivative contracts 0 5,061 0 0 5,061
Earnings fro equity method investment 0 0 0 0 0
(Gain) loss on discontinued operations 20 0 0 0 20
Other non-cash items 139 143 144 457 883
EBITDA $11,977 $15,301 $9,199 $7,480 $43,957
Credit facility borrowings $134,000
Debt/EBITDA 3.05x
35
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 discoun ted 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)
Op r 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
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NASDAQ: AXAS