Abraxas Petroleum Corporate Update

Transcription

Abraxas Petroleum Corporate Update
January 2015
Forward-Looking Statements
The information presented herein may contain predictions, estimates and other forwardlooking 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.
2
I. Abraxas Petroleum Overview
3
Corporate Profile
NASDAQ: AXAS
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Headquarters.......................... San Antonio
EV/BOE(2,3,4)………………………...
Employees...............................
114
Shares outstanding(1)…….........
107.7 mm
Proved Reserves(7).…………..... 31.0 mmboe
% Oil…………………………..
~67%
% Proved developed…..
~44%
Market cap(3) …………………….... $316.6 mm
Production(5).……………………… 7,076 boepd
Net debt(2)…………………………..
$58.8 mm
R/P Ratio(6)………………………….
PV-10(7)………………………………..
$425.8 mm
2015E CAPEX…………………….
Fully diluted shares outstanding as of September 30, 2014.
Total debt including RBL facility, rig loan and building mortgage less cash as of September 30, 2014.
Share price as of December 31, 2014.
Enterprise value includes working capital deficit (excluding current hedging assets and liabilities) as of September 30, 2014, but does not include building mortgage or rig loan. Includes RBL facility, rig loan and building mortgage less cash as of June 30, 2014.
Average production for the quarter ended September 30, 2014.
Calculation using average production for the quarter ended September 30, 2014 annualized and net proved reserves as of December 31, 2013.
Proved reserves as of December 31, 2013. Uses SEC TTM average pricing of $97.33/bbl and $3.67/mcf.
$14.09
12.0x
$200 mm
4
Abraxas Highlights
Premier
Position
 Exposure to "core" acreage in Bakken, Eagle Ford and Permian
 Targeted acreage acquisitions in geologically controlled areas of core basins
Value +
Growth
 Disciplined, ROR focused development model
 Visible/repeatable growth
Significant
Flexibility
 CAPEX can be swiftly reduced in matter of weeks in all areas if oil prices dictate
 Company owned rig in Bakken; Short term commitment in Eagle Ford
Financially
Sound
 ~ 1.0x debt/ FTM EBITDA (1)
 High margin, crude oil weighted production base
Experienced
Leadership
(1)
 Senior management with average 33 years of industry experience
FTM debt calculation excludes building mortgage and rig loan which are secured by the building and rig, respectively. EBITDA definition per bank loan agreement (excludes Rig EBITDA).
Management projection of forward EBITDA.
5
Reserve / Production Summary
High-quality, Long-Lived, Oil Weighted Assets
Proved Reserves(1) – 31.0 mmboe
Canada
1%
Permian
19%
Production(2) – 7,076 boepd
Permian
13%
Canada
1%
Gulf Coast/
Eagle Ford
46%
Rockies
34%
Gulf Coast/
Eagle Ford
34%
Rockies
52%
Reserve Mix(1)
Revenue By Production Stream(2)
NGL Sales
5%
NGL
7%
Gas Sales
7%
Gas
26%
Oil
67%
(1)
(2)
Net proved reserves as of December 31, 2013.
For the quarter ended September 30, 2014.
Oil Sales
88%
6
Prudent Growth
Growing Oil Volumes while Prudently Managing the Balance Sheet
Daily Oil Production vs. Debt/TTM Recurring EBITDA (3)
7,000
6.0x
6,000
(Bopd)
5,000
4.0x
4,000
3.0x
3,000
2.0x
2,000
1.0x
1,000
0.0x
0
2010A
2011A
2012A
Oil Production
(1)
(2)
(3)
(Debt/TTM Recurring EBITDA)
5.0x
2013A
9M14A (1)
2015E (2)
Debt/TTM Recurring EBITDA (3)
9M14A Debt/EBITDA calculated using TTM 9M EBITDA.
2015 estimate assumes the midpoint of 2014 guidance of 8,900 – 9,200 boepd and 2014 guidance for an average 71% crude oil production percentage.
Total Debt includes RBL facility, Rig Loan and Building Loan. TTM recurring EBITDA. Equivalent to Revenue – Realized Hedge Settlements – LOE – Production Taxes – Cash G&A – Other Expenses.
Does not include EBITDA contribution from Raven Drilling or contributions from liquidated hedge settlements.
7
Core Regions
Abraxas Petroleum Corporation
Williston:
Bakken / Three Forks
Proved Reserves (mmboe)(1):
 Proved Developed(1):
 Liquids(1):
31.0
44%
74%
Powder River Basin:
Turner
Legend
Delaware Basin:
Montoya/Devonian/Miss Gas,
Shallow Oil, Emerging Hz Oil
Eastern Shelf:
Conventional & Emerging Hz Oil
Rocky Mountain
Gulf Coast
Permian Basin
Eagle Ford Shale
(1)
Net proved reserves as of December 31, 2013.
8
II. Strategic Plan
9
2015 Capital Budget Flexibility
Original 2015 Plan

Eagle
Ford



Bakken



Permian



Leasing/
Other
Adjustments
Continuous one rig drilling
program throughout 2015
17 gross/17 net completions
$137.2 million budget

Continuous one rig drilling
program throughout 2015
$40.8 million budget

New drill program scheduled to
begin in April 2015
$9.9 million budget

Budgeted $12.1 million for
leasing/other


Current commodity price collapse lead to
a reevaluation of 2015 capital plan
Rig has been released
Adjusted 2015 Plan



Maintain drilling program, but delay
completions until winter abates



Adjusted Eagle Ford budget = $11.9
million
Can swiftly increase activity pending
commodity price recovery
No near term lease expiree issues
Net income from rig acts as a credit to
well cost = acceptable returns at far
lower commodity prices
Abraxas plans to maintain ~$41
million program
Current commodity price collapse lead to
a reevaluation of 2015 capital plan
New drill /recomplete/rework budget
cancelled


Adjusted Permian budget = $0
Can swiftly increase activity pending
commodity price recovery
Budget highly flexible and dependent
upon suitable opportunities


Highly flexible
Dependent upon forecasted delta
between discretionary cash flow –
drilling capex and suitable
opportunities
10
Strategic Plan – 2015+
Considering Potential 2015 Capital Plan Adjustments
Business Plan:
2015 and Beyond

FOCUSED
DEVELOPMENT
RATE OF RETURN
DRIVEN GROWTH







PRUDENT FINANCIAL
MANAGEMENT
(1)
(2)
(3)





Focused, high quality drilling inventory
▫ Add individual units in Bakken and Eagle Ford in specific geologic areas
▫ Better match of cash flow to CAPEX and subsequent returns
Visible and predictable growth profile
Ability to utilize FCF and balance sheet to bolster production, reserves and inventory with bolt on
acquisitions primarily in the Bakken and Eagle Ford(1)
Production growth the outcome of making sound financial decisions
Utilize proven operating/engineering competency to drive down costs and enhance well performance
Year over year average production still expected to grow meaningfully albeit with a lower 2015 exit rate(2)
Any potential acquisitions would have to be immediately accretive on an NAV and cash flow basis while
maintaining stated leverage goals
Potential to supplement revised production growth profile with bolt on acquisitions in a distressed
environment (1)
Properly capitalized balance sheet
Target leverage ~1.0x FTM EBITDA(3)
Maintain clean capital structure
Drilling Capital Budget cut to ~$53.8 million from $200 million
Adjusted capital plan forecasted to generate FCF at current strip (2)
No guarantee can be made as to management finding or transacting on acquisitions at acceptable terms.
Based on internal management projections.
FTM debt calculation excludes building mortgage and rig loan which are secured by the building and rig, respectively. EBITDA definition per bank loan agreement (excludes Rig EBITDA).
Management projection of forward EBITDA.
11
III. Abraxas Petroleum Financial Overview
12
2014/15 Operating and Financial Guidance
4Q14E
2015E
Production
Low
High
Low
High
Total (Boepd)
6,700
6,800
7,200
7,300
% Oil
67%
69%
% NGL
10%
9%
% Natural Gas
24%
22%
Targeted Exit Rate (Boepd)
8,500
NA
Low
High
Low
High
$10.00
$12.00
$10.00
$12.00
Production Tax (% Revenue)
8.5%
9.0%
8.5%
9.0%
Cash G&A ($mm)
$5.0
$5.5
$11.5
$12.5
Operating Costs
LOE ($/BOE)
CAPEX (midpoint, $mm)
$52.5
$53.8
13
Strong Financial Performance
Return on Total Assets (%) (1,3)
Return on Stockholders Equity (%) (1, 2)
40
50
30
40
30
20
20
10
10
0
0
Co 1. AXAS Co 2. Co 3. Co 4. Co 5. Co 6. Co 7. Co 8. Co 9.
AXAS Co 1. Co 2. Co 3. Co 4. Co 5. Co 6. Co 7. Co 8. Co 9.
BOPD/Debt Adjusted Share (5)
Return on Total Revenue (%) (1,4)
60
75
60
40
45
30
20
15
0
0
Co 1. Co 2. Co 3. AXAS Co 4. Co 5. Co 6. Co 7. Co 8. Co 9.
(1)
(2)
(3)
(4)
(5)
(6)
2010A
2011A
2012A
2013A
9M14A
2015E (6)
OGJ150 Quarterly, September 2014. Includes companies whose accounting methods vary. Excludes companies whose results were inflated by identifiable extraordinary gains. Excludes royalty trusts.
Other companies include: Mid-Con Energy Partners LP, Dorchester Minerals LP, Prime Energy Corp, Hess Corp, Continenal Resources, Humble Energy, Exxon Mobil Corp, Reserve Petroleum, Co, New Source Energy.
Other companies include: Dorchester Minerals LP, Reserve Petroleum Co, Mid-Con Energy Partners LP, Spindletop Oil & Gas Co, Hess Corp, Quicksilver Resources Inc., Wexpro, New Source Energy Partners and Fidelity Exploration and Production Co.
Other companies include: Dorchester Minerals LP, Gulfport Energy Corp, New Source Energy Partners, Mid-Con Energy Partners LP, Wexpro, Reserve Petroleum, EQT Production, Evolution Petroleum Corp, Fidelity Exploration and Production..
Debt adjusted shares calculated using total shares outstanding at the end of the period and debt divided by share price at the end of the period. 2015 share price uses share price as of September 30, 2014
Assumes the midpoint of 2015 guidance and oil percentage.
14
IV. Asset Base Overview
15
Positioned in Core Areas
4,999 Net Acres
North Fork Area
 McKenzie County, ND
Lillibridge Area
 McKenzie County, ND
South Elm Coulee Area
 Richland County, MT
South Elm Coulee
Lillibridge
North Fork
16
North Fork/Lillibridge Potential
North Fork






15 completed wells
4 wells drilling
Planned nine multi-well pads at 660 foot spacing
38 additional wells at 660 foot spacing
Additional 2nd and 3rd Bench Three Forks potential
Approved by NDIC
Lillibridge






8 completed wells
East & West pad: on production
Planned two multi-well pads at 660 foot spacing
Eight additional wells at 660 foot spacing
Additional 2nd and 3rd Bench Three Forks potential
Approved by NDIC
17
North Fork/Lillibridge Performance/Economics
Middle Bakken: Type Curve Assumptions
40
Abraxas Internal Assumptions
 536 MBOE gross type curve
▫ 78% Oil
▫ Initial rate: 17,540 bopm
▫ di: 99.5%
▫ dm: 7.0%
▫ b-factor: 1.5
 CWC: $8.5 million
ROR (%)
D&M/Booked Assumptions
 434 MBOE gross type curve
▫ 78% Oil
▫ di: 99.0%
▫ dm: 7.0%
▫ b-factor: 1.5
Middle Bakken: ROR vs CAPEX (1)
30
20
10
0
$7,250
$8,250
$9,250
$10,250
CAPEX (M$)
Abraxas Bakken Wells, McKenzie ND
20 Well Average vs Type
900
120
BBLS
Abraxas Internal Type Curve
60
D&M/Booked Type Curve
300
30
WELL COUNT
90
600
0
0
1
31
61
91
121
151
181
211
241
271
301
331
361
DAYS
(1)
Uses Abraxas internal type curve and strip pricing as of December 1, 2014.
18
Focused on Execution
(1)
(2)
(3)
Well
Objective
Lat. Length (1)
Stages (1)
30-day IP (boepd) (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
Stenehjem 2H
Three Forks
10,000
33
NA
Producing
Stenehjem 3H
Middle Bakken
10,000
33
NA
Producing
Stenehjem 4H
Three Forks
10,000
33
NA
Producing
Jore 5H
Middle Bakken
10,000
NA
NA
Drilling lateral
Jore 6H
Middle Bakken
10,000
NA
NA
Intermediate cased
Jore 7H
Middle Bakken
10,000
NA
NA
Intermediate cased
Jore 8H
Middle Bakken
10,000
NA
NA
Intermediate cased
Producing, first downspacing test
Represents the average lateral length and number of stages for each group of wells.
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.
Represents average per well performance over 27 average days of production.
19
Abraxas’ Eagle Ford Properties
~10,611 Net Acres
Jourdanton Area
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
 940 net acres
Yoakum Area (not shown)
 Dewitt and Lavaca County
 Dry gas
 1,908 net acres
Cave Area
Dilworth East
Area
20
Eagle Ford
Jourdanton
Jourdanton
 7,352 net acre lease block, 100% WI
 90+ well Eagle Ford potential
 Austin Chalk and Buda also prospective
 North Fault Block
▫
▫
▫
▫
▫
Held by production
Seven wells drilled
37+ additional potential well locations
Grass Farm 2H: waiting on completion
Grass Farm 3H: postponed
 South Fault Block
▫
▫
▫
One well drilled
47+ additional potential well locations
First Well – Cat Eye 1H: producing
 Total
▫
▫
90+ potential well locations
7,433 net acres
21
Eagle Ford
Jourdanton Performance/Economics
Jourdanton Area: Type Curve Assumptions
15
10
5
$6,500
$7,500
$8,500
$9,500
CAPEX (M$)
20
450
15
300
10
150
Blue Eyes ESP Repair
5
0
0
0
(1)
WELL COUNT
0
$5,500
Jourdanton Area Eagle Ford Wells - BOE vs Type Curve
600
BOE
20
ROR (%)
 300 gross MBoe curve
▫ 87% oil
▫ di: 97.00%
▫ dm: 7%
▫ b-factor: 1.3
 CWC: $7.0 million (5,000 foot lateral)
Jourdanton Area: ROR vs CAPEX (1)
15
30
45
60
75
90
105 120 135 150 165 180 195 210 225 240 255 270 285 300 315 330 345 360
DAYS
Uses strip pricing as of December 1, 2014.
22
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
▫
 Dutch 4H
▫
(1)
23
Eagle Ford
Cave Area Performance/Economics
Cave Area: Type Curve Assumptions
Cave Area: ROR vs CAPEX (1)
30
ROR (%)
 584 MBoe gross type curve
▫ 83% oil
▫ di: 98.0%
▫ dm: 7.0%
▫ b-factor: 1.3
20
10
0
$10,000
$11,000
$12,000
$13,000
CAPEX (M$)
Cave Area Eagle Ford Wells - BOE vs Type Curve
1200
1000
BOE
4
600
400
SI for #3H & #4H Fracs
2
200
0
WELL COUNT
6
800
0
0
(1)
8
15
30
45
60
75
90
105 120 135 150 165 180 195 210 225 240 255 270 285 300 315 330 345 360
DAYS
Uses strip pricing as of December 1, 2014.
24
Eagle Ford
Dilworth East
Dilworth East
 940 acre lease block, 100% WI
 9 additional locations (red)
 5,000’+ lateral length
 R. Henry 2H
▫ 30 day IP: 780 boepd (1)
▫ On production
 Additional 2014 Activity
▫
R. Henry 1H: Waiting on completion
 Abraxas Type Curve
▫
▫
(1)
283 Mboe (44% oil)
CWC: $7.5 million
25
Eagle Ford
Focused on Execution
(1)
(2)
(3)
Well
Area
Lat. Length
Stages
30-day IP (boepd)
T-Bird 1H
Status
Nordheim
5,102
15
1,202 (2)
Sold
13 WyCross Wells
WyCross
5,000 – 7,500
18 – 29
466 – 1,184 (1,2)
Sold
Blue Eyes 1H
Jourdanton
5,000
22
527 (2,3)
Producing
Producing
Snake Eyes 1H
Jourdanton
5,000
18
759 (2,3)
Spanish Eyes 1H
Jourdanton
5,000
19
213 (2,3)
Producing
Producing
Eagle Eyes 1H
Jourdanton
3,800
18
249 (2,3)
Ribeye 1H
Jourdanton
7,000
21
240 (2,3)
Producing
Producing
Ribeye 2H
Jourdanton
7,000
28
389 (2,3)
Cat Eye 1H
Jourdanton
7,000
NA
NA
Completing
Grass Farm 2H
Jourdanton
5-7,000
NA
NA
Waiting on completion
Grass Farm 3H
Jourdanton
5-7,000
NA
NA
Postponed
Dutch 2H
Cave
9,000
36
1,093 (2)
Producing
Dutch 1H
Cave
9,000
37
786
Producing
Dutch 3H
Cave
9,000
37
888
Producing
Dutch 4H
Cave
9,000
37
926
Producing
R Henry 2H
Dilworth East
5,000
19
780
Producing
R. Henry 1H
Dilworth East
5,000
NA
NA
Waiting on completion
Represents the range for WyCross wells.
30 day IP equivalent to highest 30 days of production after the well was placed on sub-pump.
26
Why Abraxas?
Low Risk Bakken and Eagle Ford Development
Substantial Unbooked Potential Upside
Significant Operational and Financial Flexibility
Strong Rate of Return Driven Production Growth
Prudent Financial Management
27
Appendix
28
Additional Assets
Opportunity Overview
Abraxas Assets
2014 Development
 Stacked pay, liquids-rich horizontal
opportunities in Campbell,
Converse and Niobrara Counties,
Wyoming
 Primarily in Converse and Campbell
counties
 Hedgehog State 16-2H: Cum prod. (31
mos): 260 mboe, 26% Oil
 Marketing portion of assets:
 Appx 2,088 net acres at Porcupine
and 14,755 net acres at Brooks Draw
 Combined production of appx 250
boepd (29% oil)
Raven
Drilling
 Abraxas 100% wholly owned
subsidiary
 $18.1 million in NBV secured
against $5.1 million in rig debt (2)
 One 2,000 horsepower, SCR walking
rig currently pad drilling in the Bakken
 Subsidiary includes man camp and
additional related rig equipment
 No capital budgeted for 2015
Building
 Appraised value approximately $6.1
million secured against $4.4 million
building mortgage (2)
 24,924 square foot office building in
San Antonio, Texas that serves as
corporate headquarters
 Surface ownership in numerous
legacy areas
 $8.0 million of Purchase /
Appraised / Tax Value (3)
 Surface : 162 acres Coke, TX; 613
acres Scurry, TX; 1,769 acres in San
Patricio, TX; 12,178 acres Pecos, TX;
582 acres McKenzie, ND; 50 acres
DeWitt, TX;
 Yards/Offices: Sinton, TX; Scurry,
Texas; Dickenson, ND
Powder
River Basin
Surface /
Yards / Field
Offices
(1)
(2)
(3)
Average net production for the month ending December 2013.
As of September 30, 2014
As of December 31, 2013
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
30
Powder River Basin
Campbell & Converse Co., WY
Powder River Basin: Turner Sandstone
 Porcupine Field
▫ 26/9 gross/net wells
 Hedgehog State 16-2H
▫ Cum Production (1): 260 mboe
▫ Gross/net: 68/58 mbo
▫ Gross/net: 1,152/973 mmcf
▫ Current Production (2)
▫ 57 bopd, 808 mcfpd, 39 bpd NGLs
Hedgehog 16-2H Production
(1)
(2)
Cum production estimated through 10/31/14.
Monthly average for the month of September 2014.
31
Abraxas’ “Hidden” Gas Portfolio
Edwards (South Texas)
 PDP: 8.3 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 (5)
▫
20% ROR at $4.30/mcfe realized price (5)
▫
Refrac: $0.7 million well / 0.5 bcfe EUR / F&D $1.40/mcfe
▫
Montoya / Devonian (Delaware Basin, West Texas)
2012 Ward County Acquisition
 Acquisition of Partners’ Interests in West Texas






(1)
(2)
(3)
(4)
(5)
Purchase Price
PDP PV -15
Production
Reserves
Production
Reserves:
$6.7mm(1)
$6.7mm(2)
1,440 mcfepd
7.613 bcfe
$4,650/mcfe/day
$.88/mcfe
Net of purchase price adjustments
PV10 calculated using strip pricing as of 5/1/12
Based on December 31, 2013 reserves.
Management estimate based on previously booked PUD reserves.
Management estimate
 PDP 17.1 bcfe (net) (3)
▫
Caprito 98 01U Devonian: 39.0 bcfe gross
▫
Howe GU 5 1 Devonian: 31.7 bcfe gross
 Previous risked offsetting PUD locations: 29.7 bcfe (net) (4)
▫
12 gross/ 6 net locations dropped to PRUD (SEC 5 year rule)
 Montoya economics
▫
$5.0 million well / 6.6 bcfe EUR / F&D $.75/mcfe (5)
▫
 Devonian economics
▫
$5.8 million well / 7.6 bcfe EUR / F&D $0.76/mcfe (5)
▫
Other
 Eagle Ford Shale, Yoakum: 1,908 net acres / ~24 net locations, unbooked
 PRB, Turner (~50% gas): 2 gross (1.7 net) PUD / 50 gross (13 net) PRUD
locations, 40.6 bcfe (net) (3)
 Permian, Hudgins Ranch: 3 gross / 2.6 net PSUD locations, 9.1 bcfe (net) (5)
 Williston Basin, Red River: 1 gross / .8 net PRUD location, 2.1 bcfe (net) (5)
32
Portilla Field
San Patricio County, TX
Portilla Field
100% Surface Ownership
 Annual CAPEX of ~$1 million to maintain flat
decline rate
 Infill and work over opportunities
 100% WI ownership
 Abraxas owns 1,769 surface acres
 Ideal CO2 candidate,
▫ 10% additional recovery = 8 mmbo
 Cum Production (1)
▫ ~80 mmbo + ~92 bcf Gross from Frio sands
 Current Production (2)
▫ 184 boepd Net
(1)
(2)
Monthly average for the month of December 2013.
33
Permian Basin
Sharon Ridge - Westbrook: Clearfork Trend
Sharon Ridge/Westbrook: Clearfork Trend
 89 active wells
▫ San Andres, Glorietta, Clearfork
▫ Cooperative water flood on some leases
 110 potential new-drills, recompletes or workovers
 29 well development in 2015
▫ 11 recompletions
▫ 8 workovers
▫ 10 new drill wells
 Abraxas New Drill Type Curve
▫
▫
31 Mbo (100% oil)
Gross/Net CWC: $0.75/$0.6 million
34
Permian Basin
Reeves/Ward County Bone Spring/Wolfcamp Potential
Ward County
 2,592/2,196 gross/net
acres
 28 potential (1) gross Wolfcamp locations
▫
▫
▫
▫
(1)
prospective (1)
Potential (1) Wolfcamp locations shown in green
Wolfcamp production shown in red
Wolfcamp permits show in in blue
Wells shown > 7,600’
Ward County
 413/340 gross/net prospective (1) acres
 3 potential (1) gross 2nd Bone Spring locations
▫
▫
▫
Potential (1) Bone Spring locations shown in green
Bone Spring production shown in red
Wells shown > 7,600’
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 D&M.
35
Permian Basin
Bell, Cherry and Brushy Canyon Production
Abraxas Cherry Canyon Field:
 30 Active Wells, three zones
 Waterflood potential
▫ 27 active wells
▫ Eight Proposed Injection Wells
 Horizontal potential
 Cum production (1)
▫ ~5 mmboe Gross
 Current production (2)
▫ 150 boepd Net
(1)
(2)
36
Permian Basin
Howe Deep
Howe Deep:




One active Montoya well
Five active Devonian wells
Horizontal Wolfcamp Potential
Cum production (1)

Current production (2)
▫ ~62 bcf Gross
▫ 1,325 mcfepd Net
(1)
(2)
37
Permian Basin
R.O.C. Deep
R.O.C. Deep:




Six active Montoya wells
Four active Devonian wells
One active Ellenburger well
Cum production (1)
▫ ~138 bcf Gross

Current production (2)
▫ 1,290 mcfepd Net
(1)
(2)
38
Abraxas Hedging Profile
(1) Straight line average price.
(2) PDP volumes per December 31, 2013 reserve report.
(3) Per the midpoint of Abraxas 2015 guidance provided on December 16, 2014. Abraxas does not provide
guidance for 2016 or 2017.
39
NASDAQ: AXAS
40

Abraxas Petroleum Corporate Update

Transcription

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