Vine Energy Inc. DUG Haynesville: Doubling Down - May 27, 2021
←
→
Page content transcription
If your browser does not render page correctly, please read the page content below
Vine Energy Inc. DUG Haynesville: Doubling Down May 27, 2021
Disclaimer
This Presentation (“Presentation”) contains selected information about Vine Energy Inc. and its consolidated subsidiaries, (“we”, “us”, the “Company” or “Vine”). Neither the Company nor any of its
subsidiaries or affiliates have any obligation to update this Presentation.
Information contained in this Presentation concerning our industry and the markets in which we operate, including our general expectations and market position, market opportunity and market
size, is based on information from our management’s estimates and research, as well as from industry and general publications and research, surveys and studies conducted by third parties. In
some cases, we do not expressly refer to the sources from which this information is derived. Management estimates are derived from publicly available information, our knowledge of our industry
and assumptions based on such information and knowledge, which we believe to be reasonable. These and other factors could cause our future performance to differ materially from our
assumptions and estimates.
This Presentation contains certain “forward-looking statements.” All statements, other than statements of historical facts, included in this Presentation that address activities, events, future
strategy, other intentions or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Forward-looking statements can be
identified by, among other things, the use of forward-looking language, such as “believes,” “expects,” “estimates,” “may,” “will,” “should,” “could,” “seeks,” “plans,” “intends,” “anticipates,” “projects”
or “scheduled to,” or other variations of such terms or comparable language. Without limiting the generality of the foregoing, forward-looking statements contained in this Presentation specifically
include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including the Company’s drilling program, production, derivative
instruments, capital expenditure levels and other guidance included in this Presentation. These statements are based on certain assumptions made by the Company based on management’s
experience and perception of historical trends, current conditions, anticipated future developments, the impact of the COVID-19 pandemic and other factors believed to be appropriate. Such
statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those
implied or expressed by the forward-looking statements. These include, but are not limited to, changes in oil and natural gas prices, weather and environmental conditions, the timing of planned
capital expenditures, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, legal or
regulatory developments affecting the Company’s business and other important factors that could cause actual results to differ materially from those described herein. As a result, you are
cautioned not to place undue reliance on these forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made, and the Company
undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.
This Presentation has been prepared at a time of increased volatility in the global economy due to the COVID-19 pandemic. The Company cannot anticipate all the ways in which the current
global health crisis and resulting financial market conditions could impact the Company's business. Consequently, certain forward-looking statements, data and assumptions in this Presentation
continue to be evaluated and refined on an ongoing basis and are subject to material change.
This Presentation provides disclosure of the Company’s proved, probable and possible reserves, which are those quantities of oil and gas, which can be estimated with reasonable certainty to be
economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which
contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the
estimation. The reserve estimates presented in this Presentation are based on reports prepared by W.D. Von Gonten & Co., the Company’s independent reserve engineers. We may use the
terms “reserve potential” and “EUR per well” to describe estimates of potentially recoverable hydrocarbons. These are the Company’s internal estimates of hydrocarbon quantities that may be
potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. These quantities may not constitute “reserves” within the meaning of the Society of
Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. EUR estimates and drilling locations have not been risked by Company
management. Actual locations drilled and quantities that may be ultimately recovered from the Company’s interests will differ substantially. There is no commitment by the Company to drill all of
the locations that have been attributed to these quantities. Factors affecting ultimate recovery include the scope of our ongoing drilling program, which will be directly affected by the availability of
capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual
drilling results, including geological and mechanical factors affecting recovery rates. Estimates of EUR per well and reserve potential may change significantly as development of the Company’s
oil and gas assets provides additional data. Our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates
from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.
The historical and projected financial information in this Presentation includes financial information that is not presented in accordance with generally accepted accounting principles (“GAAP”),
such as LQA Adj. EBITDAX, Adj. EBITDAX Margin, and free cash flow. The Company's management uses this information in its internal analysis of results and believes that this information may
be informative to investors in gauging the quality of the Company’s financial performance, identifying trends in our results and providing meaningful period-to-period comparisons. Non-GAAP
financial measures should not be used as substitutes for the corresponding GAAP measures. Non-GAAP measures in this Presentation may be calculated in a way that is not comparable to
similarly titled measures reported by other companies.
2
V INE . P URE . F OCUSED .
Vine Energy at a Glance: A Top-Tier Natural Gas Player
Industry Leading Economic Profile
LTM Q1-2021 Adj. LTM Q1-2021 Adj. LQA Q1-2021 Adj
EBITDAX(1) EBITDAX Free Cash Flow(3)
Margin(2)
$538MM 72% $82MM
Top-tier industry margin
Highly Productive Asset Base
Single Well Breakeven PV-10 Q1 2021A
Payback Period(4) Price(4) Production
~ 14 Months $1.91 945
MMcfd
Large, Contiguous Resource Position
Net Effective Acres Gross Locations / Proved Reserves(7)
Years of Inventory(6)
227,000 878 / 25 3.2Tcf (SEC)
(5)
(1) Adjusted EBITDAX is a non-GAAP financial measure. We define Adjusted EBITDAX as our net income before interest expense, income taxes, depreciation, depletion and amortization, exploration expense,
strategic expense, impairment of oil and gas properties, unrealized earnings on derivatives and other non-cash operating items. Refer to the appendix for a reconciliation to the nearest GAAP measure.
(2) Adj. EBITDAX Margin is a non-GAAP financial measure, which we calculate by dividing Adjusted EBITDAX by revenue (excluding unrealized gain/loss on derivatives).
(3) Adjusted Free Cash Flow is a non-GAAP financial measure which we define as Adjusted EBITDAX less the sum of cash interest, capital incurred and cash tax payments and distributions. Refer to the appendix
for a reconciliation to the nearest GAAP measure.
Note: Refer to Appendix for footnotes 4-7
3
V INE . P URE . F OCUSED .
Stacked Development Viability
Intersection of Historical Activity Includes Significant Unproven Acreage Core of The Core for Two Reservoirs
Historical Haynesville Activity
Historical Mid-Bossier Activity
Stacked Interval DSUs
LA North
TX North
LA Core
Liquids Rich
Natchitoches
LA South Fault Zone
Central
Shelby
TX South Updip
TX South Downdip
4
V INE . P URE . F OCUSED . Source: Haynesville Play Fundamentals | Stacked Pay Primer | ENVERUS.COM
Assets Located in Over Pressured Core of Both Haynesville and Mid-Bossier Fairways
Haynesville Mid-Bossier
Eastern portion of play has highest productivity in the basin Vine leads industry in knowledge and development of Mid-Bossier
⁻ Highest reservoir pressure drives deliverability ⁻ Vine acreage overlies the highest reservoir pressure and original gas-
⁻ High porosity and permeability consistent across leasehold in-place in the basin
⁻ High TOC and low clay content yield superior resource quality ⁻ Thick reservoir averaging over 250’ of net pay
⁻ High original gas-in-place supports 4-6 wells / section development Vine has drilled over 55 Mid-Bossier wells since 2015 with results
comparable to best Haynesville wells
Consistency of reservoir drives predictable performance across acreage
Mid-Bossier is a primary target on large part of acreage
HaynesvilleHaynesville
Production TGIP
Heat Over
Map Absolute Pressure Mid-Bossier
Mid-Bossier TGIP Over Absolute Pressure
Gas-In-Place
Vine’s assets lie within the Mid-Bossier deliverability
area of highest well Thickness is comparable with core Thickness
deliverability in the play 135’ avg Haynesville 250’ avg
Pressure Pressure
0.89 psi/ft. 0.89 psi/ft.
Porosity Porosity
8.8% 8.6%
PSI PSI
TOC TOC
3.9% 3.5%
Clay Content Clay Content
33% 42%
Gas in Place Gas in Place
128 Bcf/sec 132 Bcf/sec
Vine Assets Overlay the Core of Both Plays: Stacked Haynesville and Mid-Bossier Reservoirs
5
V INE . P URE . F OCUSED .
Select Operators Notably Target the Mid Bossier
Mid-Bossier Comprises 6%-48% of Total Operator Activity Spud After 7/1/2016
55
50
45
40
35
Record Count
30
25
20
15
10
5
0
VEI Indigo XOM BP Aethon GeoSouthern CRK
Total Producing Completed Drilled Drilling Permitted
Mid-Bossier
Total Producing Completed Drilled Drilling Permitted Play Total MB % of Total
VEI 52 49 1 2 - - 105 31%
Indigo 49 38 1 5 1 4 134 23%
XOM 38 32 1 5 - - 36 48%
BP 34 25 1 8 - - 70 27%
GeoSouthern 22 21 0 1 - - 90 19%
Aethon 32 14 5 10 1 2 162 10%
CRK 16 13 2 1 - - 247 6%
6
V INE . P URE . F OCUSED . Source: Haynesville Play Fundamentals | Stacked Pay Primer | ENVERUS.COM
2020 Actuals Exceeding Unit Economics IRRs
LateralWell
Lateral Well Cost EUREUR
Cost (BCF/ IRRIRR
@ $2.50
@ $2.50
Well
Length ($/Ft) 1000') Flat Price Actual Cum Gas/1000’ vs. Type Curve
Well Length ($/ft) (Bcf/1,000') NYMEX flat
1 ALERION 14-23HC-02 ALT
BLACKSTONE 34-3HC-01 ALT
7473
7583
$1,303
$1,137
1.9
2.1
73%
194%
Cum Production/1000’ (BCF)
BLACKSTONE 34-3HC-02 ALT 7419 $1,325 2.2 109%
2 MCKISSACK 34-3HC-01 ALT 7418 $1,140 2.1 184%
MCKISSACK 34-3HC-02 ALT 7414 $1,069 2.1 213%
MCKISSACK 34-3HC-03 ALT 7416 $1,096 2.1 161%
3 CHAMBERLIN 14-23HC-01 ALT 10070 $1,360 2.2 48%
CLARK 24-13HC-02 7313 $1,139 2.3 160%
4 CREST 30-19HC-01 ALT 7611 $1,141 1.8 64%
5 CREST 30-19HC-02 ALT
DESOTO FAM 15-22HC-01 ALT
7315
9281
$1,434
$1,246
1.9
2.4
42%
121% HV Type Curve MB Type Curve
6 DESOTO FAM 16-21HC-01 ALT 7505 $1,208 2.2 77% HV Actuals MB Actuals
DESOTO FAM 16-21HC-02 ALT 7503 $1,172 2.3 145%
7 LA MINERALS 28-33HC-03 ALT 7974 $1,244 1.8 50%
Producing Days
QUDO 2-11HC-01 ALT 7094 $1,124 2.4 159%
QUDO 2-11HC-02 ALT 7225 $1,107 2.4 168%
8 QUDO 2-11HC-03 ALT 7310 $1,129 2.4 156% 2020 HV and MB Wells Online
QUDO 2-35HC-01 ALT 7544 $1,154 2.4 168%
Haynesville Average 7693 $1,196 2.2 127%
7,500' Type Curve Economics 7500 $1,227 2.2 83%
2
BRUSHY 32-5HC-05 ALT 7496 $1,236 2.0 81% 6 3
9
BRUSHY 32-5HC-06 ALT 7441 $1,307 2.0 70% 8
GALLASPY 32-5HC-03 ALT
GALLASPY 32-5HC-04 ALT
7500
7541
$1,221
$1,382
2.0
2.0
74%
50%
4
10 5 10
CLARK 24-13HC-01
LA MINERALS 28-33HC-01 ALT
9489
9188
$1,144
$1,166
2.0
1.9
105%
80%
1 12
11 LA MINERALS 28-33HC-02 ALT 9809 $1,166 2.1 164% 9 13
12 MONDELLO 51HC-01 ALT 8844 $1,612 2.4 66%
SAN PATRICIO 12-13HC-02 ALT 9991 $1,056 1.8 104%
13 SAN PATRICIO 12-13HC-03 ALT 9901 $1,184 1.8 39%
Mid-Bossier Average 8720 $1,247 2.0 83% 11 7
7,500' Type Curve Economics 7500 $1,227 2.0 71%
Note: Wells > 6000’ 7
V INE . P URE . F OCUSED .Top Tier Well Results
Haynesville 7,500’ Well Performance(1) Relative to Peers Mid-Bossier 7,500’ Well Performance(1) Relative to Peers
• Top Haynesville rock quality • Ideal location for Mid-Bossier co-development
1,750 • Superior inventory 1,750 • Robust economics
• Best recoveries in trend • Top-tier Mid-Bossier performance
1,500 1,500
Vine Vine
Cumulative Gas (MMcf/1,000')
Cumulative Gas (Mmcf/1,000')
1,250 1,250
1,000 1,000
750 750
500 500
250 250
0 0
0 6 12 18 24 0 6 12 18 24
Normalized Month Months Online
With Lower Variability
Vine Haynesville & Mid-Bossier Core(2) Marcellus Dry Gas Core(2)
P1
Vine P2
SW Marcellus
Haynesville P5 P10/P90 = 2.3x
P10/P90 = 1.4x P10
Cumulative Probability >>>
P20
• Shallower slope indicates
• Vertical slope indicates P30
lower repeatability
higher repeatability P40
P50 • Higher P10/P90 variance
• Low P10/P90 variance P60 exhibits more variability
exhibits low variability P70
P80
Vine P90
Mid-Bossier P95 NE Marcellus
P10/P90 = 1.6x P98
P10/P90 = 3.1x
P99
100 1,000 10,000
Source: Enverus as of 11/24/2020.
8
V INE . P URE . F OCUSED . (1)
(2)
Wells turned-in-line since 2017 normalized to 7,500’ lateral.
Wells turned-in-line since 2017; Vine Core includes Burgundy & Red Haynesville and Blue & Green Mid-Bossier trend areas, Marcellus Core includes Enverus-defined Core and Tier 1 Dry Gas sub-plays.Vine Haynesville & Mid-Bossier vs. NW Haynesville
Shape Matters
Type Curve Comparison Productivity and Single Well Economics @ $2.75/MMBtu
Haynesville Vine HV Vine MB NW HV
25,000
Gas Production, Mcfd
20,000
15,000 IRR @ $2.75 Flat, % 110% 97% 47%
10,000
5,000
0
0 5 10 15 20 25 30 35 40 45 50 PV10, $MM $8.2 $5.9 $8.0
Months
Vine HV NW HV
Mid-Bossier Payback, Years 1.0 1.0 1.7
25,000
Gas Production, Mcfd
20,000
15,000
10,000 EUR, Bcf/1,000 ft 2.3 2.0 2.0
5,000
0
0 5 10 15 20 25 30 35 40 45 50
Months Well Cost, $/ft $1,227 $1,227 $1,283
Vine MB NW HV
Notes:
1) Normalized to 7,500 ft lateral 9
V INE . P URE . F OCUSED . 2) Economics based on 100% WI and 80% NRIDrilling Days Historical Performance
Drilling Days Performance By Lateral Category, Year By Year
60
54.9
55
49.4
50
47.3
46.1
45
42
41.1
40 39 38.6
37.6
36.3 36.4
35 33.6 33.6 34.1 33.4
Drilling Days
30.9 31.2
30 28.8 28.9
26.2 26.6
24.7
25 23.8
23
20
15
10
5
0
Short Short Cross Long 10k
(Frac Efficiency
Pumping Hours per Day (PHPD) Feet per Day (FPD) Stages per Day (SPD) Pumping, Sand & Trucking Cost/ft
Q121 AVG: 15.12 Q121 AVG: 858 Q121 AVG: 5.39 Q121 AVG: $389
4% 15% 11% 13%
2020 AVG: 14.60 2020 AVG: 746 2020 AVG: 4.87 2020 AVG: $445
Pophope 12.9 Pophope 769 Pophope 4.88 PopHope $310 $393
Scales Heirs 14.3 Scales Heirs 819 Scales Heirs 5.13 Scales Heirs $286 $364
Sabine 16.7 Sabine 970 Sabine 6.13 Sabine $300 $383
Qudo 15.2 Qudo 896 Qudo 5.60 Qudo $278 $358
Clark 14.2 Clark 720 Clark 4.52 Clark $361 $446
2020 14.6 2020 746 2020 4.87 2020 $350 $445
2019 12.6 2019 619 2019 4.48 2019 $424 $534
2018 11.8 2018 536 2018 4.47 2018 $443 $592
10 12 14 16 18 500 600 700 800 900 1,000 3 4 5 6 7 $- $200 $400 $600
• 2nd best quarter (Q120 – 1st, 15.3) • New quarterly record (Q120 – 2nd, 816) • 2nd best quarter (Q120 – 1st, 5.64) • New quarterly record (Q420 – 2nd, $419)
11
V INE . P URE . F OCUSED .Total Well Costs
Efficiency Driving Cost Reductions
$1,800 8,000
$1,659 $1,681 $1,676 7,348
7,145
$1,600 7,000
$1,484
$1,424
$1,400 6,039
5,776 6,000
$1,242
$1,200 5,019
5,000
4,367
Avg. Lateral Length
$1,000
4,000
$ /ft
$800
3,000
$600
2,000
$400
$200 1,000
$0 0
2015 2016 2017 2018 2019 2020
$/ft Average Lateral Length
12
V INE . P URE . F OCUSED .ESG Leader Focused on Clean Energy Footprint
CO2e* MT / MBOE / Well by Basin CO2e* MT / MBOE / Well by Peer
20.9
23.35
20.28
15.23 12.5
11.0 11.6
9.6
8.6 8.7
8.25 6.7 6.8 6.8
5.8 5.7 5.7 6.1 6.3
4.7
3.5 4.0
3.20
Haynesville Barnett Eagle Ford Marcellus/ Permian
Utica
*CO2e includes CO2, Methane, Nitrous Oxide Peers include: Aethon, BP, Cabot, Chesapeake, Chevron, Cimarex, Concho, Comstock, Continental, Devon,
Diamondback, Equinor, Gulfport, Oxy, Pioneer, Range, Shell
HS&E Efforts Governance & Social Impacts
• 62% reduction in CH4/MBoe since 2017 • $1.4B of economic contributions (CY’17 – CY’19)
• 35% reduction in C02e/MBoe since 2017 Local property and production taxes
• All drilling rigs utilize bi-fuel engines Royalties, wages & benefits and capital expenditures
25% of pressure pumping equipment utilizing bi-fuel
• Early adoption of intermittent-bleed control valves
• Diverse work force is a key strength
Currently converting to zero-bleed controls significantly reducing ~40% of senior executive team is female
methane emissions
~30% of workforce is female vs. ~15% industry average
• 100% non-potable water used in all operations
• 100% green completions • Vine Cares program targets donations to local communities
• 100% of wellsite electricity provided by solar power First responders in our field areas (Police, Fire & EMS)
Under-resourced local school districts (LA Parishes)
*6-YEAR TRIR SAFETY RECORD: Children’s wellness (JDF, St. Jude, Children’s Advocacy Center)
0.0 EMPLOYEE 0.33 CONTRACTOR
*Industry Bureau of Labor Rate = 0.6
TRIR – Total Recordable Incident Rate Source: EPA Facility Level Information on Greenhouse Gases Tool. 13
V INE . P URE . F OCUSED .Appendix
The Haynesville Basin Offers Two Viable Intervals
Haynesville Accounts for 87% of Activity Spuds After 7/1/2016, Middle Bossier 13%
Total Producing Completed Drilled Drilling Permitted
Haynesville 1,598 1,139 144 180 41 94
Mid-Bossier 247 195 12 32 2 6
Haynesville % Total Wells (%) 87% 85% 92% 85% 95% 94%
Haynesville % Total Wells (%) 13% 15% 8% 15% 5% 6%
Note: Middle Bossier permits based on stacked or tightly spaced directional surveys, may not include all Mid-Bossier permits. 16
V INE . P URE . F OCUSED . Source: Haynesville Play Fundamentals | Stacked Pay Primer | ENVERUS.COMNon-GAAP Reconciliations
Adjusted EBITDAX ($ in millions) LTM Q1 2021 Q1 2021 Adjusted Free Cash Flow ($ in millions) Q1 2021
Net Income ($235) ($34) Adjusted EBITDAX $145
Income tax provision 0 0
Less: Cash Interest (27)
Income Before Income Taxes ($235) ($34)
Unrealized gain/loss on commodity derivatives 238 38 Less: Capital Incurred (98)
Non-cash G&A 0 0
Non-cash write-off of deferred IPO costs 0 0 Less: Cash Taxes (payments and distributions) 0
Non-cash volumetric adjustment 0 0 Adjusted Free Cash Flow $20
Depletion, depreciation, and accretion 407 107
Interest Expense 128 34 Annualized (x4)
$82
Strategic 1 0
Severance 0 0
Exploration 0 0
Adjusted EBITDAX $538 $145
Adjusted EBITDAX margin
Revenue $507
Unrealized loss on commodity derivatives 238
Total revenue before unrealized loss on commodity derivatives $745
Adjusted EBITDAX $538
Adjusted EBITDAX Margin 72%
17
V INE . P URE . F OCUSED .Footnotes
Footnotes Slide 3: (Vine Energy at a Glance: A Top-Tier Natural Gas Player)
4) Payback period at 12/31/2020 strip pricing. Breakeven price includes 10% rate of return. Based on remaining inventory at 1/1/2021 and YE 2020 reserve type curves.
5) Effective acreage is sum of net acreage prospective for the Haynesville and the Mid-Bossier.
6) Based on an average of 4 gross rigs with for remaining core inventory.
7) Based on 12/31/2020 strip. SEC reserves limited by 5-year window. Throughout this presentation, proved reserves and proved PV-10 have an effective date of 12/31/2020
18
V INE . P URE . F OCUSED .You can also read
