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| 8-K - 8-K - ABRAXAS PETROLEUM CORP | a8knovember2016upcomingcat.htm |
Abraxas’ Upcoming Catalysts
November 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
Headquarters.......................... San Antonio
Employees(1)............................ 83
Shares outstanding(2)……......... 135.1 mm
Market cap(4) …………………….... $218.8 mm
Net debt(3)………………………….. $95.0 mm
2017E CAPEX………………………. $60 mm
(1) Abraxas full time employees as of October 12, 2016. Does not include nine employees associated with the Company’s wholly owned subsidiary, Raven Drilling.
(2) Shares outstanding as of September 30, 2016.
(3) Total debt including RBL facility, rig loan and building mortgage less cash as of September 30, 2016.
(4) Share price as of October 31, 2016.
(5) 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 Sep tember 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.
(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 September 30, 2016.
(10) EBITDA calculated per bank loan covenant, which includes realized hedge settlements. Please see Appendix for calculation.
EV/BOE(3,4,5)………………………... $7.48
Proved Reserves(8).…………..... 43.2 mmboe
PV-10(8)……………………………….. $197.3 mm
NBV Non-Oil & Gas Assets(9).. $22.3 mm
Production(6).……………………… 5,955 boepd
R/P Ratio(7)…………………………. 19.9x
NASDAQ: AXAS
Corporate Profile
4
Williston:
Bakken / Three Forks
Powder River Basin:
Turner
Eastern Shelf:
Conventional & Emerging Hz Oil
Eagle Ford Shale
/ Austin Chalk
Delaware Basin:
Bone Spring & Wolfcamp
Rocky Mountain
South Texas
Permian Basin
Legend
Proved Reserves (mmboe)(1): 43.2
Proved Developed(1): 32%
Oil(1): 56%
Current Prod (boe/d) (2): 5,955
Abraxas Petroleum Corporation
Core Regions
(1) Net proved reserves as of December 31, 2015.
(2) Average production for quarter end September 30, 2016
2016 Capex Focus Areas
5
Area
Capital
($MM)
% of
Total
Gross
Wells
Net
Wells
Permian - Delaware $11.0 18.3% 2.0 2.0
Austin Chalk 10.5 17.5% 2.0 2.0
Bakken 36.8 61.3% 8.0 5.0
Other 1.7 2.8%
Total $60.0 100% 12.0 9.0
2017 Operating and Financial Guidance
2017 Capex Budget Allocation 2017 Operating Guidance
Operating Costs
Low
Case
High
Case
LOE ($/BOE) $6.00 $8.00
Production Tax (% Rev) 9.0% 11.0%
Cash G&A ($mm) $9.0 $11.0
Production (boepd) 7,000 7,400
(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.
$0
$50,000
$100,000
$150,000
$200,000
$250,000
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
2
0
1
2
A
2
0
1
3
A
2
0
1
4
A
2
0
1
5
A
20
16
E
(2
)
20
17
E
(2
)
Ye
a
rl
y
CA
PE
X
($
M
)
(B
O
EP
D
)
Daily Production vs Yearly CAPEX (1)
Oil Gas NGL
Oil
66%
Natural Gas
21%
2017 Expected Production Mix
NGL
13%
6
Upcoming Catalysts
7
Catalyst #1
Bakken / Three Forks
3,902 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
▫ 60 additional operated wells at 660-1320 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
(1) The 30-day average rates represent the highest 30 days of production and do not include the impact of natural gas liquids and sh rinkage at the processing plant and include flared gas.
8
Bakken / Three Forks
North Fork Economics
Middle Bakken: ROR vs CAPEX (1)
(1) Uses strip pricing as of October 5, 2016.
Abraxas Booked Assumptions
533 MBOE gross type curve
▫ 78% Oil
▫ Initial rate: 715 bopd
▫ di: 99.3%
▫ dm: 8.0%
▫ b-factor: 1.5
Booked CWC: $7.25 mill ion
Middle Bakken: Type Curve Assumptions
Abraxas Updated Assumptions
728 MBOE gross type curve
▫ 78% Oil
▫ Initial rate: 930 bopd
▫ di: 98.5%
▫ dm: 8.0%
▫ b-factor: 1.3
CWC: ~$6.0 mill ion
9
First 2 AC wells
7,776 total net acres located in the
Jourdanton Field perspective for the
Austin Chalk in Atascosa County, TX
$5.0 million D&C costs for 5,000’
laterals
Targeted EURs of ~400 mbo for 5,000’
lateral
Fist well, Bulls Eye 101H
▫ 5,865’ effective lateral
▫ On production
Impact on Abraxas
▫ With success, ~90 Gross/Net well
locations
▫ Additional acreage
Catalyst #2
Austin Chalk
10
Atascosa Trough
Vertical Chalk Production (Cumulative Oil)
Jourdanton Lease Block
Karnes Trough
Atascosa Trough
11
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
12
Catalyst #3
Permian Basin – Wolfcamp & Bone Spring – Ward/Reeves
5,248 net HBP acres located on the eastern edge of the
Delaware Basin in Reeves/Ward County
▫ Four identified potential zones (Bone Spring, Wolfcamp)
▫ Potential gross locations
▫ Caprito: 5 target intervals, 16 locations for each; 80 laterals
▫ BLK 16: 4 target intervals, 2 locations for each; 8 laterals
▫ GT Hall: 5 target intervals; 3 locations on strike for 3, 2 locations
for 2; 13 laterals
▫ Fee 57: 4 target intervals; 4 locations; 16 laterals
▫ Howe: 3 target laterals; 12 locations; 36 laterals
▫ Fidelity Tr: 3 target intervals; 2 location; 6 laterals
Offset operator 24-hour IP’s up to 1,700 Boe/d (~84% oil)
$5.95 million D&C costs for 5,000’ laterals
Wolfcamp A targeted EURs of ~500 mboe
First well Caprito 99-101H – waiting on completion
Exploring additional opportunities to expand position
Caprito 99-101H
13
Additional Delaware Acreage
Permian Basin – Wolfcamp & Bone Spring – Pecos
563 net acres located in Pecos County
Held by Production
Four potential gross locations (Wolfcamp A)
14
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
15
3rd Bone Spring and Wolfcamp
Abraxas Lease Areas:
3rd Bone Spring and
Wolfcamp A present,
relatively consistent
Lower Wolfcamp and
underlying Penn. interval,
variable
16
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
17
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.
Felix
Rock of Ages
Four Mile
Echo Canyon
Lead King
AXAS: Caprito 99-101H
18
Catalyst #4
Potential Asset Sales
(1) Inclusive of proceeds expected from Hudgins Ranch Sale of $6.7 million and Brooks Draw of $11.3 million.
(2) Average for the month of June, 2016
2016 to date, Abraxas has monetized or has under contract approximately $35.5 million(1) 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, l iquids-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 (2)
Bids not acceptable to date – will
continue to explore opportunities
to exit position
Powder
River Basin –
Brooks Draw
Stacked pay, l iquids-rich horizontal
opportunities in Converse and
Niobrara Counties, Wyoming
~14,229 net acres
~28 bopd net production (2)
PSA signed
Portilla
Large inventory conventional
targets; EOR potential
Avg production ~150 boepd, ~87% oil (2) No capital budgeted for 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
19
Abraxas Hedging Profile
(1) Straight line average price.
Q4 2016 2017 2018 2019
Oil Swaps (bbls/day) 2500 2401 1796 1200
NYMEX WTI (1) $43.25 $54.53 $47.48 $54.54
20
Appendix
21
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
22
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
23
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.
24
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.
25
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.
26
Powder River Basin
Turner Sandstone Horizontal Play
Porcupine Area: Turner Sandstone
• 2,088 net acres (100% HBP) in an active area of
Campbell and Converse counties
• 30% state / 70% federal
• Current producing wells: 5 (3 operated) (avg. operated
WI / NRI: 100% / 83%)
• Average net production(1): 121 Boe/d (29% liquids)
Powder River Basin: Other Areas (not shown)
• 1,895 net acres (100% HBP)
• 49% federal / 51% fee
• Primary targets: Turner, Parkman, Teapot, Muddy
(1) August, 2016 average production.
27
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
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
28
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.
29
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
30
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)
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
arnings 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 0 0 1,665 82 1,747
Other non-cash items 457 583 36 (264) 813
EBITDA $7,480 $11,756 $13,851 $5,021 $38,108
Credit facility borrowings $90,000
Debt/EBITDA 2.36x
31
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
32
NASDAQ: AXAS