vine energy inc. dug haynesville: doubling down
TRANSCRIPT
DUG HaynesvilleVine Energy Inc.
VINE. PURE. FOCUSED. 2
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.
VINE. PURE. FOCUSED. 3
Vine Energy at a Glance: A Top-Tier Natural Gas Player
Industry Leading Economic Profile
$82MM
72% Top-tier industry margin
878 / 25 3.2Tcf (SEC)
(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
VINE. PURE. FOCUSED. 4
Intersection of Historical Activity Includes Significant Unproven Acreage Core of The Core for Two Reservoirs
VINE. PURE. FOCUSED.
Mid-Bossier Gas-In-PlaceHaynesville Production Heat Map
Eastern portion of play has highest productivity in the basin Highest reservoir pressure drives deliverability High porosity and permeability consistent across leasehold High TOC and low clay content yield superior resource quality High original gas-in-place supports 4-6 wells / section development
Consistency of reservoir drives predictable performance across acreage
Haynesville Vine leads industry in knowledge and development of Mid-Bossier
Vine acreage overlies the highest reservoir pressure and original gas- in-place in the basin
Thick reservoir averaging over 250’ of net pay Vine has drilled over 55 Mid-Bossier wells since 2015 with results
comparable to best Haynesville wells Mid-Bossier is a primary target on large part of acreage
Mid-Bossier
Haynesville TGIP Over Absolute Pressure Mid-Bossier TGIP Over Absolute Pressure
Thickness 135’ avg
Pressure 0.89 psi/ft.
Thickness 250’ avg
Pressure 0.89 psi/ft.
Gas in Place 132 Bcf/sec
Vine Assets Overlay the Core of Both Plays: Stacked Haynesville and Mid-Bossier Reservoirs
5
Assets Located in Over Pressured Core of Both Haynesville and Mid-Bossier Fairways
PSI PSIPSI
Vine’s assets lie within the area of highest well
deliverability in the play
Haynesville
VINE. PURE. FOCUSED. 6
Select Operators Notably Target the Mid Bossier Mid-Bossier Comprises 6%-48% of Total Operator Activ ity Spud After 7/1/2016
0 5
10 15 20 25 30 35 40 45 50 55
VEI Indigo XOM BP Aethon GeoSouthern CRK
Re co
rd C
ou nt
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%
Source: Haynesville Play Fundamentals | Stacked Pay Primer | ENVERUS.COM
VINE. PURE. FOCUSED.
Producing Days
Cu m
P ro
du ct
io n/
10 00
Note: Wells > 6000’
IRR @ $2.50 Flat Price
ALERION 14-23HC-02 ALT 7473 $1,303 1.9 73% BLACKSTONE 34-3HC-01 ALT 7583 $1,137 2.1 194% BLACKSTONE 34-3HC-02 ALT 7419 $1,325 2.2 109% 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% CHAMBERLIN 14-23HC-01 ALT 10070 $1,360 2.2 48% CLARK 24-13HC-02 7313 $1,139 2.3 160% CREST 30-19HC-01 ALT 7611 $1,141 1.8 64% CREST 30-19HC-02 ALT 7315 $1,434 1.9 42% DESOTO FAM 15-22HC-01 ALT 9281 $1,246 2.4 121% DESOTO FAM 16-21HC-01 ALT 7505 $1,208 2.2 77% DESOTO FAM 16-21HC-02 ALT 7503 $1,172 2.3 145% LA MINERALS 28-33HC-03 ALT 7974 $1,244 1.8 50% QUDO 2-11HC-01 ALT 7094 $1,124 2.4 159% QUDO 2-11HC-02 ALT 7225 $1,107 2.4 168% QUDO 2-11HC-03 ALT 7310 $1,129 2.4 156% 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%
BRUSHY 32-5HC-05 ALT 7496 $1,236 2.0 81% BRUSHY 32-5HC-06 ALT 7441 $1,307 2.0 70% GALLASPY 32-5HC-03 ALT 7500 $1,221 2.0 74% GALLASPY 32-5HC-04 ALT 7541 $1,382 2.0 50% CLARK 24-13HC-01 9489 $1,144 2.0 105% LA MINERALS 28-33HC-01 ALT 9188 $1,166 1.9 80% LA MINERALS 28-33HC-02 ALT 9809 $1,166 2.1 164% MONDELLO 51HC-01 ALT 8844 $1,612 2.4 66% SAN PATRICIO 12-13HC-02 ALT 9991 $1,056 1.8 104% SAN PATRICIO 12-13HC-03 ALT 9901 $1,184 1.8 39% Mid-Bossier Average 8720 $1,247 2.0 83%
7,500' Type Curve Economics 7500 $1,227 2.0 71%
10 11 12
Marcellus Dry Gas Core(2)
8
Top Tier Well Results Haynesville 7,500’ Well Performance(1) Relative to Peers
SW Marcellus P10/P90 = 2.3x
NE Marcellus P10/P90 = 3.1x
• Higher P10/P90 variance exhibits more variability
Vine Haynesville P10/P90 = 1.4x
• Low P10/P90 variance exhibits low variability
Vine Mid-Bossier P10/P90 = 1.6x
Source: Enverus as of 11/24/2020. (1) Wells turned-in-line since 2017 normalized to 7,500’ lateral. (2) 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.
With Lower Variability
Cu m
ul at
ive G
as (M
m cf/
1, 00
Cu m
ul at
ive G
as (M
M cf
/1 ,0
• Robust economics
Productivity and Single Well Economics @ $2.75/MMBtu
Vine HV Vine MB NW HV
IRR @ $2.75 Flat, % 110% 97% 47%
PV10, $MM $8.2 $5.9 $8.0
Payback, Years 1.0 1.0 1.7
EUR, Bcf/1,000 ft 2.3 2.0 2.0
Well Cost, $/ft $1,227 $1,227 $1,283
Notes: 1) Normalized to 7,500 ft lateral 2) Economics based on 100% WI and 80% NRI
0
5,000
10,000
15,000
20,000
25,000
0 5 10 15 20 25 30 35 40 45 50
Ga s P
0
5,000
10,000
15,000
20,000
25,000
0 5 10 15 20 25 30 35 40 45 50
Ga s P
2015 2016 2017 2018 2019 2020 2021
Drilling Days Historical Performance
Q121 AVG: 5.39
2020 AVG: 4.87
Q121 AVG: 15.12
2020 AVG: 14.60
Q121 AVG: 858
2020 AVG: 746
• 2nd best quarter (Q120 – 1st, 15.3) • New quarterly record (Q120 – 2nd, 816) • 2nd best quarter (Q120 – 1st, 5.64)
536
619
746
720
896
970
819
769
2018
2019
2020
Clark
Qudo
Sabine
2018
2019
2020
Clark
Qudo
Sabine
2018
2019
2020
Clark
Qudo
Sabine
15%4% 11% 13%
VINE. PURE. FOCUSED. 12
$1,659
$1,424
Av g.
La te
13Source: EPA Facility Level Information on Greenhouse Gases Tool.
3.5 4.0 4.7 5.8 5.7 5.7 6.1 6.3 6.7 6.8 6.8
8.6 8.7 9.6 11.0 11.6 12.5
20.9
8.25
20.28
15.23
3.20
23.35
Permian
HS&E Efforts
*6-YEAR TRIR SAFETY RECORD: 0.0 EMPLOYEE 0.33 CONTRACTOR
*Industry Bureau of Labor Rate = 0.6 TRIR – Total Recordable Incident Rate
Governance & Social Impacts
Peers include: Aethon, BP, Cabot, Chesapeake, Chevron, Cimarex, Concho, Comstock, Continental, Devon, Diamondback, Equinor, Gulfport, Oxy, Pioneer, Range, Shell
• 62% reduction in CH4/MBoe since 2017 • 35% reduction in C02e/MBoe since 2017 • All drilling rigs utilize bi-fuel engines
25% of pressure pumping equipment utilizing bi-fuel • Early adoption of intermittent-bleed control valves
Currently converting to zero-bleed controls significantly reducing methane emissions
• 100% non-potable water used in all operations • 100% green completions • 100% of wellsite electricity provided by solar power
• $1.4B of economic contributions (CY’17 – CY’19) Local property and production taxes Royalties, wages & benefits and capital expenditures
• Diverse work force is a key strength ~40% of senior executive team is female ~30% of workforce is female vs. ~15% industry average
• Vine Cares program targets donations to local communities First responders in our field areas (Police, Fire & EMS) Under-resourced local school districts (LA Parishes) Children’s wellness (JDF, St. Jude, Children’s Advocacy Center)
Appendix
VINE. PURE. FOCUSED. 16
The Haynesville Basin Offers Two Viable Intervals Haynesvi l le Accounts for 87% of Activ ity Spuds After 7/1/2016, Middle Bossier 13%
Total Producing Completed Drilled Drilling Permitted
Haynesville 1,598 1,139 144 180 41 94
Mid-Bossier 247 195 12 32 2 6
Haynesville % Total Wells (%) 87% 85% 92% 85% 95% 94%
Haynesville % Total Wells (%) 13% 15% 8% 15% 5% 6%
Note: Middle Bossier permits based on stacked or tightly spaced directional surveys, may not include all Mid-Bossier permits. Source: Haynesville Play Fundamentals | Stacked Pay Primer | ENVERUS.COM
VINE. PURE. FOCUSED. 17
Adjusted EBITDAX ($ in millions) LTM Q1 2021 Q1 2021
Net Income ($235) ($34) Income tax provision 0 0
Income Before Income Taxes ($235) ($34) Unrealized gain/loss on commodity derivatives 238 38 Non-cash G&A 0 0 Non-cash write-off of deferred IPO costs 0 0 Non-cash volumetric adjustment 0 0 Depletion, depreciation, and accretion 407 107 Interest Expense 128 34 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 $145
Less: Cash Interest (27)
Less: Capital Incurred (98)
Less: Cash Taxes (payments and distributions) 0 Adjusted Free Cash Flow $20
Annualized (x4) $82
238
38
0
0
238
$745
2021
2020
2020
38
- 0
- 0
Q1 2021
Adjusted EBITDAX
0
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
Vine Energy at a Glance: A Top-Tier Natural Gas Player
Stacked Development Viability
Assets Located in Over Pressured Core of Both Haynesville and Mid-Bossier Fairways
Select Operators Notably Target the Mid Bossier
2020 Actuals Exceeding Unit Economics IRRs
Top Tier Well Results
Drilling Days Historical Performance
Slide Number 14
Non-GAAP Reconciliations
VINE. PURE. FOCUSED. 2
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.
VINE. PURE. FOCUSED. 3
Vine Energy at a Glance: A Top-Tier Natural Gas Player
Industry Leading Economic Profile
$82MM
72% Top-tier industry margin
878 / 25 3.2Tcf (SEC)
(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
VINE. PURE. FOCUSED. 4
Intersection of Historical Activity Includes Significant Unproven Acreage Core of The Core for Two Reservoirs
VINE. PURE. FOCUSED.
Mid-Bossier Gas-In-PlaceHaynesville Production Heat Map
Eastern portion of play has highest productivity in the basin Highest reservoir pressure drives deliverability High porosity and permeability consistent across leasehold High TOC and low clay content yield superior resource quality High original gas-in-place supports 4-6 wells / section development
Consistency of reservoir drives predictable performance across acreage
Haynesville Vine leads industry in knowledge and development of Mid-Bossier
Vine acreage overlies the highest reservoir pressure and original gas- in-place in the basin
Thick reservoir averaging over 250’ of net pay Vine has drilled over 55 Mid-Bossier wells since 2015 with results
comparable to best Haynesville wells Mid-Bossier is a primary target on large part of acreage
Mid-Bossier
Haynesville TGIP Over Absolute Pressure Mid-Bossier TGIP Over Absolute Pressure
Thickness 135’ avg
Pressure 0.89 psi/ft.
Thickness 250’ avg
Pressure 0.89 psi/ft.
Gas in Place 132 Bcf/sec
Vine Assets Overlay the Core of Both Plays: Stacked Haynesville and Mid-Bossier Reservoirs
5
Assets Located in Over Pressured Core of Both Haynesville and Mid-Bossier Fairways
PSI PSIPSI
Vine’s assets lie within the area of highest well
deliverability in the play
Haynesville
VINE. PURE. FOCUSED. 6
Select Operators Notably Target the Mid Bossier Mid-Bossier Comprises 6%-48% of Total Operator Activ ity Spud After 7/1/2016
0 5
10 15 20 25 30 35 40 45 50 55
VEI Indigo XOM BP Aethon GeoSouthern CRK
Re co
rd C
ou nt
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%
Source: Haynesville Play Fundamentals | Stacked Pay Primer | ENVERUS.COM
VINE. PURE. FOCUSED.
Producing Days
Cu m
P ro
du ct
io n/
10 00
Note: Wells > 6000’
IRR @ $2.50 Flat Price
ALERION 14-23HC-02 ALT 7473 $1,303 1.9 73% BLACKSTONE 34-3HC-01 ALT 7583 $1,137 2.1 194% BLACKSTONE 34-3HC-02 ALT 7419 $1,325 2.2 109% 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% CHAMBERLIN 14-23HC-01 ALT 10070 $1,360 2.2 48% CLARK 24-13HC-02 7313 $1,139 2.3 160% CREST 30-19HC-01 ALT 7611 $1,141 1.8 64% CREST 30-19HC-02 ALT 7315 $1,434 1.9 42% DESOTO FAM 15-22HC-01 ALT 9281 $1,246 2.4 121% DESOTO FAM 16-21HC-01 ALT 7505 $1,208 2.2 77% DESOTO FAM 16-21HC-02 ALT 7503 $1,172 2.3 145% LA MINERALS 28-33HC-03 ALT 7974 $1,244 1.8 50% QUDO 2-11HC-01 ALT 7094 $1,124 2.4 159% QUDO 2-11HC-02 ALT 7225 $1,107 2.4 168% QUDO 2-11HC-03 ALT 7310 $1,129 2.4 156% 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%
BRUSHY 32-5HC-05 ALT 7496 $1,236 2.0 81% BRUSHY 32-5HC-06 ALT 7441 $1,307 2.0 70% GALLASPY 32-5HC-03 ALT 7500 $1,221 2.0 74% GALLASPY 32-5HC-04 ALT 7541 $1,382 2.0 50% CLARK 24-13HC-01 9489 $1,144 2.0 105% LA MINERALS 28-33HC-01 ALT 9188 $1,166 1.9 80% LA MINERALS 28-33HC-02 ALT 9809 $1,166 2.1 164% MONDELLO 51HC-01 ALT 8844 $1,612 2.4 66% SAN PATRICIO 12-13HC-02 ALT 9991 $1,056 1.8 104% SAN PATRICIO 12-13HC-03 ALT 9901 $1,184 1.8 39% Mid-Bossier Average 8720 $1,247 2.0 83%
7,500' Type Curve Economics 7500 $1,227 2.0 71%
10 11 12
Marcellus Dry Gas Core(2)
8
Top Tier Well Results Haynesville 7,500’ Well Performance(1) Relative to Peers
SW Marcellus P10/P90 = 2.3x
NE Marcellus P10/P90 = 3.1x
• Higher P10/P90 variance exhibits more variability
Vine Haynesville P10/P90 = 1.4x
• Low P10/P90 variance exhibits low variability
Vine Mid-Bossier P10/P90 = 1.6x
Source: Enverus as of 11/24/2020. (1) Wells turned-in-line since 2017 normalized to 7,500’ lateral. (2) 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.
With Lower Variability
Cu m
ul at
ive G
as (M
m cf/
1, 00
Cu m
ul at
ive G
as (M
M cf
/1 ,0
• Robust economics
Productivity and Single Well Economics @ $2.75/MMBtu
Vine HV Vine MB NW HV
IRR @ $2.75 Flat, % 110% 97% 47%
PV10, $MM $8.2 $5.9 $8.0
Payback, Years 1.0 1.0 1.7
EUR, Bcf/1,000 ft 2.3 2.0 2.0
Well Cost, $/ft $1,227 $1,227 $1,283
Notes: 1) Normalized to 7,500 ft lateral 2) Economics based on 100% WI and 80% NRI
0
5,000
10,000
15,000
20,000
25,000
0 5 10 15 20 25 30 35 40 45 50
Ga s P
0
5,000
10,000
15,000
20,000
25,000
0 5 10 15 20 25 30 35 40 45 50
Ga s P
2015 2016 2017 2018 2019 2020 2021
Drilling Days Historical Performance
Q121 AVG: 5.39
2020 AVG: 4.87
Q121 AVG: 15.12
2020 AVG: 14.60
Q121 AVG: 858
2020 AVG: 746
• 2nd best quarter (Q120 – 1st, 15.3) • New quarterly record (Q120 – 2nd, 816) • 2nd best quarter (Q120 – 1st, 5.64)
536
619
746
720
896
970
819
769
2018
2019
2020
Clark
Qudo
Sabine
2018
2019
2020
Clark
Qudo
Sabine
2018
2019
2020
Clark
Qudo
Sabine
15%4% 11% 13%
VINE. PURE. FOCUSED. 12
$1,659
$1,424
Av g.
La te
13Source: EPA Facility Level Information on Greenhouse Gases Tool.
3.5 4.0 4.7 5.8 5.7 5.7 6.1 6.3 6.7 6.8 6.8
8.6 8.7 9.6 11.0 11.6 12.5
20.9
8.25
20.28
15.23
3.20
23.35
Permian
HS&E Efforts
*6-YEAR TRIR SAFETY RECORD: 0.0 EMPLOYEE 0.33 CONTRACTOR
*Industry Bureau of Labor Rate = 0.6 TRIR – Total Recordable Incident Rate
Governance & Social Impacts
Peers include: Aethon, BP, Cabot, Chesapeake, Chevron, Cimarex, Concho, Comstock, Continental, Devon, Diamondback, Equinor, Gulfport, Oxy, Pioneer, Range, Shell
• 62% reduction in CH4/MBoe since 2017 • 35% reduction in C02e/MBoe since 2017 • All drilling rigs utilize bi-fuel engines
25% of pressure pumping equipment utilizing bi-fuel • Early adoption of intermittent-bleed control valves
Currently converting to zero-bleed controls significantly reducing methane emissions
• 100% non-potable water used in all operations • 100% green completions • 100% of wellsite electricity provided by solar power
• $1.4B of economic contributions (CY’17 – CY’19) Local property and production taxes Royalties, wages & benefits and capital expenditures
• Diverse work force is a key strength ~40% of senior executive team is female ~30% of workforce is female vs. ~15% industry average
• Vine Cares program targets donations to local communities First responders in our field areas (Police, Fire & EMS) Under-resourced local school districts (LA Parishes) Children’s wellness (JDF, St. Jude, Children’s Advocacy Center)
Appendix
VINE. PURE. FOCUSED. 16
The Haynesville Basin Offers Two Viable Intervals Haynesvi l le Accounts for 87% of Activ ity Spuds After 7/1/2016, Middle Bossier 13%
Total Producing Completed Drilled Drilling Permitted
Haynesville 1,598 1,139 144 180 41 94
Mid-Bossier 247 195 12 32 2 6
Haynesville % Total Wells (%) 87% 85% 92% 85% 95% 94%
Haynesville % Total Wells (%) 13% 15% 8% 15% 5% 6%
Note: Middle Bossier permits based on stacked or tightly spaced directional surveys, may not include all Mid-Bossier permits. Source: Haynesville Play Fundamentals | Stacked Pay Primer | ENVERUS.COM
VINE. PURE. FOCUSED. 17
Adjusted EBITDAX ($ in millions) LTM Q1 2021 Q1 2021
Net Income ($235) ($34) Income tax provision 0 0
Income Before Income Taxes ($235) ($34) Unrealized gain/loss on commodity derivatives 238 38 Non-cash G&A 0 0 Non-cash write-off of deferred IPO costs 0 0 Non-cash volumetric adjustment 0 0 Depletion, depreciation, and accretion 407 107 Interest Expense 128 34 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 $145
Less: Cash Interest (27)
Less: Capital Incurred (98)
Less: Cash Taxes (payments and distributions) 0 Adjusted Free Cash Flow $20
Annualized (x4) $82
238
38
0
0
238
$745
2021
2020
2020
38
- 0
- 0
Q1 2021
Adjusted EBITDAX
0
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
Vine Energy at a Glance: A Top-Tier Natural Gas Player
Stacked Development Viability
Assets Located in Over Pressured Core of Both Haynesville and Mid-Bossier Fairways
Select Operators Notably Target the Mid Bossier
2020 Actuals Exceeding Unit Economics IRRs
Top Tier Well Results
Drilling Days Historical Performance
Slide Number 14
Non-GAAP Reconciliations