Investor Presentation - August 2020 - Viper Energy Partners
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Investor Presentation August 2020
Forward Looking Statements
This presentation contains “forward-looking statements” within the meaning of the securities laws. All statements, other than statements of historical fact, included in this presentation that
address activities, events or developments that Viper Energy Partners LP (“Viper,” the “Partnership,” “VNOM”, “we” or “our”) expects, believes or anticipates will or may occur in the future are
forward-looking statements. The words “believe,” “expect,” “may,” “estimates,” “will,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are
intended to identify forward-looking statements, which are generally not historical in nature. However, the absence of these words does not mean that the statements are not forward-
looking.
Without limiting the generality of the foregoing, these statements discuss future expectations, contain projections of results of operations or of financial condition or state other forward-looking
information and include statements with respect to, among other things, Viper’s ability to make distributions on the common units and expectations of plans, strategies and objectives and
anticipated financial and operating results of Viper. These statements are based on certain assumptions made by Viper based on management’s expectations and perception of historical
trends, current conditions, anticipated future developments 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 Viper, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the
factors discussed or referenced in the “Risk Factors” section of Viper’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K and in Viper’s other filings
with the Securities and Exchange Commission (the “SEC”), risks relating to financial performance and results, current adverse industry and macroeconomic conditions and resulting capital
restraints, Viper’s future cash distribution policy, depressed commodity prices and demand for oil and natural gas and impact on proved reserves, borrowing base redeterminations and
possible impairments of oil and gas interests, availability of drilling equipment and personnel, availability of sufficient capital to execute our business plan and acquisition strategy, impact of
compliance with legislation and regulations, including any regulatory action that may impose production limits on Viper’s properties, the impact and duration of the ongoing COVID-19
pandemic, including logistical challenges and the supply chain disruptions, successful results from our operators’ identified drilling locations, our operators’ ability to efficiently develop and
exploit the current reserves on our properties, any delays, curtailments or interruptions of production on our mineral and royalty acreage, our ability to acquire additional mineral and royalty
interests, our pending, completed or future acquisitions of mineral and royalty interests and other important factors that could cause actual results to differ materially from those projected.
Any forward-looking statement speaks only as of the date on which such statement is made and Viper undertakes no obligation to correct or update any forward-looking statement, whether
as a result of new information, future events or otherwise, except as required by applicable law.
Non-GAAP Financial Measures
Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and
rating agencies. Viper defines generally accepted accounting principles, or GAAP. Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate Viper’s
operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. Adjusted EBITDA should not be considered
as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of Viper’s operating performance or liquidity. Certain items excluded
from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the
historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Viper defines cash available for distribution generally as an amount equal to its Adjusted EBITDA for the
applicable quarter less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors of
Viper’s general partner may deem appropriate. Viper’s computations of Adjusted EBITDA and cash available for distribution may not be comparable to other similarly titled measures of other
companies or to such measure in its credit facility or any of its other contracts. For a reconciliation of Adjusted EBITDA to net income (loss), please refer to Viper’s filings with the SEC.
Oil and Gas Reserves
The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet
the SEC’s definitions for such terms. Viper discloses only estimated proved reserves in its filings with the SEC. Viper’s estimated proved reserves as of December 31, 2019 contained in this
presentation were prepared by Ryder Scott Company, L.P., an independent engineering firm, and comply with definitions promulgated by the SEC. Additional information on Viper’s
estimated proved reserves is contained in Viper’s filings with the SEC.
In this communication, Viper may use the terms “resources,” “resource potential” or “potential resources,” which the SEC guidelines prohibit Viper from including in filings with the SEC.
“Resources,” “resource potential” or “potential resources” refer to Viper’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or
recovered with additional drilling or recovery techniques. Such terms do not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management
System or SEC rules and does not include any proved reserves. Actual quantities that may be ultimately recovered by the operators of Viper’s properties will differ substantially. Factors
affecting ultimate recovery include the scope of the operators’ ongoing drilling programs, 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 potential resources may change significantly as development of our properties by our operators provide additional data. In addition,
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.
2
Viper: Investment Highlights
2Q ‘20 cash available for distribution of $0.12/unit; Board approved distribution of $0.03 with remaining available
cash to be retained for balance sheet strength
Q2 2020 Review 2Q ‘20 average oil production of 14,453 Bo/d, up 9% year over year
134 total gross (2.4 net 100% royalty interest) horizontal wells with average lateral of 8,648’ turned to production
during 2Q ‘20
Q3 2020 / Q4 2020 average production guidance of 14,750 – 16,000 Bo/d (24,500 – 26,500 Boe/d), the midpoint of
which is up 6% from 2Q ‘20 average daily oil production
FY 2020 production guidance of 15,250 – 16,000 Bo/d (25,250 – 26,250 Boe/d)
Durable Free
Cash Flow Relationship with Diamondback and diversified exposure to other well-capitalized operators within the Permian Basin
Profile and Eagle Ford Shale support Viper’s production profile
High cash margins, no capital requirements and limited operational costs drive continuous free cash flow generation
Strong free cash flow generation and variable equity distribution model enables cash flow flexibility
24,714 net royalty acres positioned in the core of the Permian Basin and Eagle Ford Shale with 14 rigs currently
operating on Viper’s acreage
Unmatched Size
and Scale Proved reserves as of December 31, 2019 of 88.9 MMBoe (78% PDP, 54.4 MMBo), up 41% year over year
Strong liquidity position of $436 million with low G&A burden and limited interest expense as primary cash expenses
485 gross (8.1 net 100% royalty interest) horizontal wells in the process of active development
Undeveloped 440 line-of-sight wells with visibility to potential of future development in coming quarters, but which are not
Inventory currently in the process of active development, in which Viper expects to own an average 2.0% NRI (8.8 net
Supports Long- 100% royalty interest wells)
Term Growth Largely undeveloped, concentrated acreage throughout the core of the Permian under competent
operators, primarily Diamondback, provides long-term organic growth potential
Viper’s Mineral and Royalty Interests Provide Significant Exposure to Perpetual Ownership of High Margin,
Largely Undeveloped Assets with Zero Capital Requirements to Support its Sustainable Free Cash Flow (1)
Source: Partnership data and filings. Data as of 6/30/2020 unless otherwise noted.
(1) Approximately 87% of Viper’s royalty assets are perpetual; the remaining royalty assets are overriding royalty interests that are subject to lease expirations and not perpetual.
3
Viper Energy Partners Overview
Differentiated Investment Opportunity Viper Mineral and Royalty Assets
Unique Relationship with Primary Operator VNOM royalty acreage
Diamondback relationship and ownership reduces
uncertainty around pace of development
FANG acreage
Free Cash Flow Positive Through the Cycle
High margins, no capital requirements and limited
operating costs drive continuous free cash flow generation
Perpetual Ownership with Priority Claims(1)
Mineral interests have claim to first-dollar-out
At expiration of lease, all rights revert to mineral owner
Significant Undeveloped Resource
Permian assetFree Cash Flow Sensitivity
Due to its high return and high cash margin structure, Viper’s free cash flow is resilient to changes in
commodity prices; further upside to commodity prices in 2021 as hedges roll off
At $40 oil and production held flat relative to its 2H 2020 guidance levels, Viper is expected to
generate >$180 million in free cash flow on an annualized basis in the first half of 2021, or a greater
than 11% free cash flow yield
Illustrative 2H 2020E and 1H 2021E Annualized Free Cash Flow Based on 2H 2020 Production Guidance(1)
2H 2020 Annualized FCF 1H 2021 Annualized FCF
Assumptions
Annualized FCF Yield @ Guidance Midpoint $250
14.75 – 16.00 Mbo/d
Oil Production
Annualized Free Cash Flow ($MM)
24.50 – 26.50 Mboe/d $200
Total Production
$6.5 Million
Cash G&A $150
14.0%
$32 Million 12.9%
Interest Expense(2) 11.5%
9.8% $100
7% of Revenue 8.2%
11.4%
Prod. & Ad Valorem Taxes 10.5%
9.7%
8.9%
25% of WTI / $1.00/Mcf 7.7% $50
Realized NGL / Gas Prices
~95% $0
% of WTI Realized ($/Bbl)
$30.00 $35.00 $40.00 $45.00 $50.00
Source: Partnership data and filings. Financial data as of 6/30/2020. Yield based on unit closing price as of 7/31/2020.
(1) Free cash flow defined as operating cash flow before changes in working capital. Includes hedge gain/(loss).
(2) Roughly approximates total interest expense based on 5.375% fixed interest payments on $480 million Sr. Notes due 2027, 3.0% interest on $153mm drawn on the revolving credit facility and a
0.4% non-use fee on the undrawn capacity of the revolving credit facility. 5Portfolio Overview
134 gross (2.4 net) horizontal wells turned to production during Q2 2020
Near-term inventory of 8.1 net wells currently in the process of active development and an
additional 8.8 net line-of-sight wells not currently being developed
14 gross rigs currently operating on Viper’s acreage, 4 of which are operated by Diamondback
No acquisitions were completed during Q2 2020, leaving Viper’s footprint of mineral and royalty
interests at a total of 24,714 net royalty acres
Diamondback Operated Third Party Operated
Midland Delaware Midland Delaware Eagle Ford Total
Net Royalty Acres 7,384 5,231 5,194 6,224 681 24,714
2Q ‘20 Gross Hz Wells Turned to
Production (Net 100% NRI Wells)
10 (0.9) 4 (0.3) 47 (0.6) 37 (0.4) 36 (0.2) 134 (2.4)
Gross Producing Hz Locations
(Net 100% NRI Wells)
733 (65.8) 346 (18.6) 1,077 (28.6) 985 (15.6) 1,339 (7.6) 4,480 (136.2)
Gross Active Rigs
(Net 100% NRI Rigs)
4 (0.1) 0 (0.0) 7 (0.1) 3 (0.1) 0 (0.0) 14 (0.3)
Gross Work-in-Progress(1)
(Net 100% NRI Wells)
40 (4.2) 26 (1.0) 252 (1.4) 97 (1.2) 70 (0.3) 485 (8.1)
Gross (Net) Line-of-Sight(2) 53 (3.6) 21 (0.7) 179 (2.2) 146 (2.1) 41 (0.2) 440 (8.8)
Source: Partnership data and estimates and DrillingInfo. Acreage as of 6/30/2020; activity data as of 7/14/2020. Existing permits or active development of Viper’s royalty acreage does not ensure
that those wells will be turned to production given the current depressed oil prices.
(1) Work in progress wells represent those that have been spud and are expected to be turned to production within approximately the next six to eight months.
(2) Line-of-sight wells are those that are not currently in the process of active development, but for which Viper has reason to bel ieve that they will be turned to production within approximately
the next 15 to 18 months. The expected timing of these wells is based primarily on permitting by third party operators or Diamondback’s current expected completion schedule.
6Near-Term Inventory Summary and Forward Visibility
Diamondback has recently brought three completion crews back to work after taking an almost
three-month break from all completion activity in the second quarter of 2020
Diamondback expects to focus its completion activity on areas where Viper has significant royalty
interests, primarily in the Midland Basin
Visibility into third party operators’ anticipated activity levels has remained limited due to current
depressed commodity price environment, but has increased in recent months
100% NRI Work-in-Progress(1) 100% NRI Line-of-Sight(2) 100% NRI Near-Term Inventory
OTHER
15% OTHER OTHER
23% 24%
PXD 2%
COP 3%
EOG 3%
COP 2% FANG
XTO 5% 8.1 PE 3% 8.8 49%
COP 2%
XTO 4%
16.8 FANG
XTO 4% 56%
SM 8% FANG SM 4%
64%
CXO 8% CXO 4%
PXD 6%
PXD 11%
Diamondback and Other Well-Capitalized Operators Support Viper’s Production Profile
Source: Partnership data and estimates. Existing permits or active development of Viper’s royalty acreage does not ensure that those wells will be turned to production given the current depressed
oil prices.
(1) Work in progress wells represent those that have been spud and are expected to be turned to production within approximately the next six to eight months.
(2) Line-of-sight wells are those that are not currently in the process of active development, but for which Viper has reason to bel ieve that they will be turned to production within approximately
the next 15 to 18 months. The expected timing of these wells is based primarily on permitting by third party operators or Diamondback’s current expected completion schedule.
7Diamondback DUC Backlog Overview
Diamondback’s DUC Backlog on Viper’s Royalty Acreage as of 6/30/2020
VNOM royalty acreage
FANG acreage Andrews/Martin: 10-15 gross DUCs
Average NRI: 4.5%
Average Lateral: 9,200’
Howard: 20-25 gross DUCs
Average NRI: 2.0%
Average Lateral: 10,200’
Midland: 20-25 gross DUCs
Average NRI: 16.5%
Average Lateral: 11,100’
N. Delaware 0-5 gross DUCs
Average NRI: 0.5%
Average Lateral: 10,400’
Glasscock: 0-5 gross DUCs
Average NRI: 12.5%
Average Lateral: 7,500’
ReWard: 15-20 gross DUCs
Average NRI: 3.0%
Average Lateral: 10,100’
Pecos: 25-30 gross DUCs
Average NRI: 4.0%
Average Lateral: 10,200’
Viper Has Meaningful Exposure to Approximately 65% of Diamondback’s Total Gross DUCs
Source: Partnership data and estimates. DUC backlog as of 6/30/2020.
8Significant Undeveloped, Concentrated Resource
Highly Concentrated Acreage in Midland Basin Illustrative Remaining Midland Basin Resource
12,578 VNOM
Net Royalty Acres
Assumed 1.5
Assumed 25%
mile lateral
lease royalty
(240 NRA)
13.1 Net Drilling Spacing
Units (100% NRI)
28 wells
per 1.5
mile DSU
~365 illustrative net
Estimated 900
100% NRI VNOM
MBoe EUR/well
locations
~329 MMBoe
Total Resource
% Developed ~270 remaining
~95 producing
net locations
% Undeveloped net locations
(>70% undeveloped;
(Significant Undeveloped, Concentrated Resource
Highly Concentrated Acreage in Delaware Basin Illustrative Remaining Delaware Basin Resource
11,456 VNOM
Net Royalty Acres
Assumed 1.5
Assumed 25%
mile lateral
lease royalty
(240 NRA)
11.9 Net Drilling Spacing
Units (100% NRI)
20 wells
per 1.5
mile DSU
~240 illustrative net
Estimated 1,000
100% NRI VNOM
MBoe EUR/well
locations
~240 MMBoe
Total Resource
% Developed
~205 remaining
~35 producing
net locations
% Undeveloped net locations
(>85% undeveloped;
(Spectrum of Oil and Gas Interest Ownership
~87% of Viper’s Royalty Assets
Own rights in perpetuity; all development rights revert to mineral owner at
1 expiration of lease
Perpetual Mineral Revenue is received from E&P companies as lessor royalties from producing wells
Interest(1) located on leased lands
~13% of Viper’s Royalty Assets (55% of which operated by FANG)
Overriding Royalty
2 Royalty interests carved out of lessee’s leasehold interest
Interest (ORRI)
Burdens working interest and expires with underlying lease
Volumetric Production Structured investment that relates to a specific amount of
Payment
3 production for a pre-determined amount of time
Royalties paid based on the profitability of a defined area
Net Profit Interest
4 Royalty collector exposed to operating and capital costs,
typically excluding environmental liabilities
Acreage is leased from a mineral owner
Working Interest
5 Responsible for drilling wells (if they are the operator)
and associated capital and operating costs
Minerals Provide the Greatest Form of Protection Available in the Oil Industry Due Perpetual Ownership and
Priority Claims with Right to First-Dollar-Out
Source: Partnership data and filings. Acreage as of 6/30/2020.
(1) Includes non-participating royalty interests.
11Illustrative Delaware Basin Oil & Gas Lease Life Cycle
Sign New
Lease
2015: Minerals Leased 2018: Extension 2021: CDC Expires
• 25% royalty • No development by • Operator does not
• Lease bonus operator within drill any additional
• 3-year primary term primary term wells
• 180-day CDC(1) • Another lease bonus • Lease terminates for
• Lease requires 4 wells to mineral owner 1/1/2020 7/1/2020 any land/depths not
to hold 640 acres per • Maintain other Held-by-Production
zone requirements of lease
Operator drills Operator drills Extend
2 WCA(2) wells 1 2BS(4) well Lease
Pugh Clause
Security of Mineral Ownership
Mineral ownership remains safest asset in the oil
industry because it is a perpetual, real property
1 Mile
1 Mile
interest
Lease terms like “Continuous Development
Clause” and “Pugh Clause” allow for 1 Mile 1 Mile
development rights to revert to mineral owner if no 320 acres of 320 acres of
WCA HPB(3) WCA HPB
development by lessee &
160 acres of
Right to receive compensation in various forms 2BS HPB
and right to first-dollar-out with priority claims
(1) CDC: Continuous Development Clause.
(2) WCA: Wolfcamp A.
(3) HBP: Held by Production.
(4) 2BS: Second Bone Spring. 12How Viper Defines a “Net Royalty Acre”
Methodology for deriving “Net Royalty Viper’s Formula for Net Royalty Acreage
Acreage” differs widely across the industry
Many companies calculate assuming there
are eight royalty acres for every one net Net Lease Net
Royalty
mineral acre (NMA) Mineral Royalty
Acres and other
burdens Acres
Viper derives its total net royalty acreage
from net mineral ownership taking into Viper believes its methodology more accurately defines its
consideration the royalty interest AND all acreage for which it will receive revenue
other burdens
Acreage Definition Comparison NRA Example Assuming Standard ¼ Royalty
640
NMA 160 NRA
Viper Net Royalty Acres 24,714
Mineral Royalty
640-acre Acres Acres
section
Viper Net Royalty Acres
(Normalized to 1/8) 197,712
100%
Mineral 640 1,280
0 50,000 100,000 150,000 200,000 Interest NMA NRA
Mineral Royalty
Acres Acres
Source: Partnership data and filings. Acreage data as of 6/30/2020.
13Financial Overview
Financial Strategy Viper Capitalization
Maintain Financial Flexibility
($ in millions) 6/30/2020
♦ Borrowing base of $580 million with only $154 million
drawn as of 6/30/2020 Cash $10
♦ Maintain strong liquidity and optionality with cash flow Revolving Credit Facility 154
to strengthen balance sheet
Borrowing Base 580
Availability Under Revolver 426
Use of Cash Available for Distribution up to Board of
Directors’ Discretion Each Quarter Senior Notes 486
♦ Historically (through 2019) had paid substantially all Liquidity $436
cash available to unitholders through quarterly
Net Debt / LTM EBITDA 2.5x
distributions
♦ 75% of available cash from 1Q ‘20 and 2Q ‘20 retained Guidance Update
to strengthen balance sheet
Q3/Q4 2020 Net Oil Production – Mbo/d 14.75 – 16.00
Downside Protection Provided through Hedges
Q3/Q4 2020 Net Total Production – Mboe/d 24.50 – 26.50
♦ Majority of 2020 oil production hedged through collars
Full Year 2020 Net Oil Production - Mbo/d 15.25 – 16.00
♦ Downside protected in 2020 to $30 oil for large portion
of expected production Full Year 2020 Net Total Production – Mboe/d 25.25 – 26.25
Unit Costs ($/boe)
No Direct Operating or Capital Expenses
Cash G&A $0.60 - $0.80
♦ Focus on mineral and royalty interests preserves low-
cost structure Non-Cash Equity Based
$0.10 - $0.25
Compensation
♦ Expected production and ad valorem taxes of 7.0% of
royalty income Depletion $9.50 - $11.50
♦ Operators bear capital burden, allowing Viper to Production and Ad Valorem Taxes (% of
7% - 8%
generate continuous free cash flow Revenue)(1)
Interest Expense(2) $3.25 - $3.75
Source: Partnership data and filings.
(1) Includes production taxes of 4.6% for crude oil and 7.5% for natural gas and NGLs and ad valorem taxes.
(2) Assumes 1H 2020 actual interest expense plus interest expense for the remainder of 2020 assuming $480mm in principal of Sr. Notes and $155mm drawn on the revolver.
14Hedge Update
Crude Oil (Bbls/day, $/Bbl) Q3 2020 Q4 2020 FY 2021
1,000 1,000 -
Swaps - WTI
$27.45 $27.45 -
Costless Collars - WTI 14,000 14,000 10,000
Floor $28.86 $28.86 $30.00
Ceiling $32.33 $32.33 $43.05
Deferred Premium Call Options - WTI - 8,000 -
Premium - -$1.89 -
Strike - $45.00 -
4,000 4,000 -
Basis Swaps - WTI (Midland-Cushing)
-$2.60 -$2.60 -
Natural Gas (Mmbtu/day, $/Mmbtu) Q3 2020 Q4 2020 FY 2021
Natural Gas Basis Swaps - 25,000 25,000 -
Waha Hub -$2.07 -$2.07 -
Source: Partnership data as of 6/30/2020.
15Final Thoughts
Viper Energy Partners offers sustainable free cash flow, substantial
remaining inventory and upside to future strength in commodity prices
Mineral ownership provides surest form of security in the oil industry
Relationship with Diamondback provides visibility to production and
cash flow growth
Royalty assets offer organic growth without any capital costs or
operating expenses
Strong free cash flow generation with financial flexibility
Advantaged tax structure that enables non-taxable distributions
(1) Last eight quarterly quarterly distributions reasonably determined to not constitute dividends for U.S. federal income tax purposes; rather constitute non-taxable reductions to tax basis.
16Viper Energy Partners LP Kaes Van’t Hof, President
500 West Texas Ave., Suite 1200 (432) 221-7430
Midland, TX 79701 minerals@viperenergy.com
www.viperenergy.com
Adam Lawlis, Vice President, Investor Relations
(432) 221-7430
ir@viperenergy.com
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