Attached files
| file | filename |
|---|---|
| 8-K - 8-K - ABRAXAS PETROLEUM CORP | a8kfebruaryupdate.htm |
Abraxas Petroleum
Corporate Update
February 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
Headquarters......................... . San Antonio
Shares outstanding(1)……......... 165.9 mm
Market cap(1) …………………….... $355.0 mm
Net debt(1)……………………………. $86.0 mm
2018E CAPEX……………………….. $140 mm
(1) Shares outstanding as of December 31, 2017. Market cap using share price as of February 16, 2018. Total debt including RBL facility and building mortgage less cash as of December 31, 2017
(2) Enterprise value includes working capital deficit (excluding current hedging assets and liabilities) as of September 30, 2017, but does not include building mortgage. Includes RBL facility and building mortgage less cash as of December 31, 2017.
(3) Proved reserves as of December 31, 2017. See appendix for reconciliation of PV-10 to standardized measure.
(4) Net book value of other assets as of September 30, 2017.
(5) Average production for the quarter ended December 31, 2017
(6) PV-10 calculated using SEC pricing of $51.34/bbl of oil and $2.99/mcf of natural gas. Please see appendix for reconciliation to standardized measure.
EV/BOE(1,2)…………………………… $7.01
Proved Reserves(3)………………. . 65.9 mmboe
NBV Non-Oil & Gas Assets(4)… $21.3 mm
Production(5).……………………….. 8,785 boepd
PV-10(6)…………………………………. $425.9
NASDAQ: AXAS
Corporate Profile
4
Key Investment Highlights
Recent well completion in Eagle Ford testing modern completion techniques currently producing
First Austin Chalk completion confirmed geologic concept
No capital allocated in 2018
Stephens Inc. retained to evaluate options to maximize value of the assets
Austin Chalk/ Eagle Ford
Optionality
Total bank debt of ~$84 million (3) represents the only meaningful leverage (2, 3) of the Company
Liquidity of ~$52 million (4) positions the Company to remain acquisitive
Management continues to pursue and execute on non-core asset sales
2018 drilling and completion CAPEX forecasted to remain within cash flow (5)
Balance Sheet Strength with
Solid Liquidity & Financial
Flexibility
12 gross (9 net) operated Wolfcamp/Bone Spring wells planned for 2018
10 gross (4.7 net) operated Bakken/Three Forks wells planned for 2018
Total drilling and completion CAPEX of $105 million funded out of cash flow (5) provides 44% YoY
production growth using the midpoints of 2017 and 2018 guidance
Visible Production Growth and
Fully Funded Capex Program
(1) Includes 900+ net acres associated with acquisition expected to close in February 2018
(2) Company also has $3.7 million of debt associated with a building mortgage.
(3) As of December 31, 2017
(4) Includes $1 million in cash as of December 31, 2017
(5) Based on guidance provided on slide 5. Assumes strip pricing as of January 20, 2017. Includes only drilling and completion CAPEX and does not account for acquisitions.
9,208(1) net HBP acres prospective for the Wolfcamp A, B & Bone Spring intervals
Multi-zone development across acreage position
Continue to actively lease and pursue acquisitions – recent acquisitions of ~4,000 net acres
Allocated 2018 capital budget of $71 million (51% of total allocation)
Delaware Basin Exposure
5
2018 Operating and Financial Guidance
2018 Capex Budget Allocation 2018 Operating Guidance
Operating Costs
Low
Case
High
Case
LOE ($/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)
6
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
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
Wolfcamp (2)
B
ar
re
ls
o
f
Eq
u
iv
al
e
n
t
p
e
r
D
ay
(
B
o
e
p
d
)
(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.
7
Implied Value Per Acre(1,2)
(1) Calculated as Enterprise Value less reserve/production value divided by net acres. Enterprise value calculated using market cap as of January 26, 2018 and net debt as of September 30, 2017. Production/reserve value calculated as $35,000/Boepd multiplied by
quarter end September 30, 2017 average daily production.
(2) Peers include: Callon Petroleum, Centennial Development, Diamondback, Halcon, Jagged Peak, Lillis Energy, Parsley Energy, Rosehill Resources, RSP Permian. Halcon numbers are pro forma for recent divestitures and tender offers. Lillis Energy and Rosehill
Resources numbers are pro forma for recent transactions.
(3) Enterprise value of Abraxas calculated as market cap as of January 26, 2018 and net debt as of December 31, 2017. Includes $14.2 million and 900+ net acres associated with acquisition expected to close in February 2018. Abraxas production value
calculated as $35,000/Boepd multiplied by midpoint of Abraxas 1Q18 production guidance of 10,000-11,000 Boepd.
$0
$10,000
$20,000
$30,000
$40,000
$50,000
$60,000
Peer 1 (1) Peer 2 (1) Peer 3 (1) Peer 4 (1) Peer 5 (1) Peer 6 (1) Peer 7 (1) Peer 8 (1) Peer 9 (1) Peer 10 (1) Average AXAS (3)
8
Asset Base Overview
9
9,208(1) net acres located in the eastern core of the Delaware Basin
Up to five identified 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
Unique, legacy high value acreage
▫ Favorable net revenue interests – in many cases 1/8th royalty
▫ 95+% held by production
Infrastructure
▫ Two water supply wells
▫ Two 400,000 bbl lined frac pits,
▫ SWD wells and system in place
Exploring additional opportunities to expand position
Delaware Basin
Permian Basin – Wolfcamp & Bone Spring – Ward/Reeves
Map Source: Callon, Jagged Peak, Halcon, Diamondback presentations, Drilling Info and management estimates.
(1) Includes 900+ net acres associated with acquisition expected to close in February 2018
10
1
2
3 4
5 6
7 8
9
10
11 12
13
14
16
17
18
19
15
20
21
22
9
Univ Lands Beldin 3H
Jagged Peak
IP24: 1,415 BOEPD (81% Oil)
LL: 9,561’
Surrounding Delaware Activity
1
Sealy Ranch 9301H
Halcon
LL: 10,000’
2
Univ Lands Beldin 4H
Jagged Peak
LL: 10,000’
3 & 4
Caprito 82 101H & 202H
Abraxas
LL: 4,820’
5 & 6
Sealy Ranch 7902H & 7903H
Halcon
LL: 10,000’
10
Caprito 99 302H
Abraxas
IP: 997 BOEPD (83% Oil)
LL: 4,529’
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’
7 & 8
Caprito 83 304H (WC A2)
& 404 (WC B)
304H IP30: 1,014 BOEPD
(77% Oil) LL: 4,820’
14
St. Quadricorn 1617A 1H
Jagged Peak
Flowback Test: 1,500 BOEPD
LL: 10,000’
13
CRMWD-79 1H
Halcon
IP30: 1,343 BOEPD (80% Oil)
LL: 3,477’
11
Caprito 98 301HR
Abraxas
IP30: 999 BOEPD (84% Oil)
LL: 4,880’ (Wolfcamp A2)
12
Caprito 98 201H
Abraxas
IP30: 1,036 BOEPD (84% Oil)
LL: 4,880’ (Wolfcamp A1)
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’
22
Sealy Ranch
7 Permitted Wells
Halcon
LL: 10,000’
11
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 - drilling
▫ Wolfcamp A2 – Caprito 99-301H and 311H – downspacing test - drilling
Delaware Wolfcamp
Wolfcamp A1 & A2 Well Economics
Wolfcamp: ROR vs WTI
Abraxas EOY16 Assumptions
604 MBOE gross type curve
▫ 77% Oil
▫ Initial rate: 1266 boepd
▫ di: 99.95%
▫ dm: 6.0%
▫ b-factor: 1.3
Assumed CWC: $7.3 million
Wolfcamp: Type Curve Assumptions
12
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
WARD COUNTY - WOLFCAMP
WOLFCAMP A1 COMPLETIONS; WOLFCAMP A2 COMPLETIONS; LINE = EOY16 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. 28 gross additional operated Bakken/ First Bench Three
Forks locations remaining
▫ Est. 20 gross additional Second Bench Three Forks locations
remaining
▫ 3 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
▫ 42.7% net revenue interest
Lillibridge 9H-12H
▫ Four well pad drilling
(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
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
Middle Bakken: ROR vs WTI
Abraxas EOY16 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
Three Forks
North Fork Economics
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
Three Forks: ROR vs WTI
Abraxas EOY16 Assumptions
723 MBOE gross type curve
▫ 73% Oil
▫ Initial rate: 1000 boepd
▫ di: 98.5%
▫ dm: 8.0%
▫ b-factor: 1.5
Assumed CWC: $7.0 million
Three Forks: Type Curve Assumptions
16
Shut Eye 1H
9,360 net acres located in Atascosa
County, TX prospective for the Eagle
Ford and Austin Chalk
Shut Eye 1H – EF Test
▫ Producing
▫ Enhanced completion design
▫ Encouraging early performance
Evaluating options to maximize value
of the asset
Jourdanton
Eagle Ford/Austin Chalk
17
Appendix
18
(1) 2018 daily volumes indicated for February – December 2018. January 2018 volumes equate to 3,050 Bopd hedged at $50.43.
(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) 3,885 2,383 1,200
NYMEX (1) $52.51 $55.44 $54.33
19
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
20
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)
31-Dec-16 31-Mar-17 30-Jun-17 30-Sep-17 TTM
Net income ($5,302) $13,691 $7,194 ($770) $14,813
Net interest expense 859 395 389 753 $2,396
Income tax expense 0 0 0 0 $0
Depreciation, depletion and amortization 6,500 5,374 4,415 7,878 $24,166
Amortization of deferred financing fees 256 138 116 100 $610
Stock-based compensation 784 770 979 750 $3,283
Impairment 0 0 0 0 $0
Unrealized (gain) loss on derivative contracts 6,285 (8,760) (5,071) 6,873 ($674)
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
(G i ) l ss o i continued operations 0 0 0 0 $0
Expenses incurred with offerings and execution of loan agreement 0 3,790 703 199 $4,692
Other non-cash items 139 112 113 113 $477
EBITDA $9,521 $15,507 $8,838 $15,896 $49,762
Credit facility borrowings $64,250
Debt/EBITDA 1.29x
21
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, 2016 and 2017:
December 31,
(in thousands) 2016 2017
PV-10 $160,600 $425,936
Present value of future income taxes discounted at 10% — 32,448
Standardized measure of discounted future net cash flows $160,600 $393,578
22
NASDAQ: AXAS