10-K 1 viper201810-k.htm VIPER 10-K Document

 
 
 
 
 
 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
ý
ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
OR
o

TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-36505
 
Viper Energy Partners LP
(Exact Name of Registrant As Specified in Its Charter)
 

Delaware
 
46-5001985
(State or Other Jurisdiction of
Incorporation or Organization)
 
(IRS Employer
Identification Number)
 
 
500 West Texas, Suite 1200
Midland, Texas
 
79701
(Address of Principal Executive Offices)
 
(Zip Code)
(432) 221-7400
(Registrant Telephone Number, Including Area Code)
 
 
Securities registered pursuant to Section 12(b) of the Act:
 
 
 
Title of Each Class
 
 
 
Name of Each Exchange on Which Registered
 
 
Common Units Representing Limited Partner Interests
 
 
 
The Nasdaq Stock Market LLC
 
 
 
Securities registered pursuant to Section 12(g) of the Act: None
(Global Select Market)
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes ý   No  o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ý    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check One):
Large Accelerated Filer
 
ý
 
Accelerated Filer
 
o
Non-Accelerated Filer
 
o
 
Smaller Reporting Company
 
o
 
 
 
 
Emerging Growth Company
 
o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
The aggregate market value of the common units held by non-affiliates was approximately $1,288,629,954 on June 29, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, based on closing prices in the daily composite list for transactions on the Nasdaq Global Select Market on such date. As of January 31, 2019, 51,653,956 common units representing limited partner interests and 72,418,500 Class B units representing limited partner units were outstanding.
Documents Incorporated By Reference: None
 
 
 
 
 
 
 
 
 
 



VIPER ENERGY PARTNERS LP
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2018
TABLE OF CONTENTS
 
 
Page
 
 
PART I
 
 
PART II
 
 
PART III
 
 
PART IV







GLOSSARY OF OIL AND NATURAL GAS TERMS
The following is a glossary of certain oil and natural gas industry terms used in this Annual Report on Form 10-K (the “Annual Report” or this “report”):
3-D seismic
Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.
Basin
A large depression on the earth’s surface in which sediments accumulate.
Bbl
Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
BOE
Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/d
Barrels of oil equivalent per day.
British Thermal Unit or Btu
The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion
The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Condensate
Liquid hydrocarbons associated with the production that is primarily natural gas.
Crude oil
Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Deterministic method
The method of estimating reserves or resources under which a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation is used in the reserves estimation procedure.
Developed acreage
Acreage allocated or assignable to productive wells.
Development costs
Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves.
Development well
A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
Differential
An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Dry hole or dry well
A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Exploitation
A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
Field
An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Finding and development costs
Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.
Fracturing
The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.
Gross acres or gross wells
The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drilling
 A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.
Horizontal wells
Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
MBbls
Thousand barrels of crude oil or other liquid hydrocarbons.
MBOE
One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Mcf
Thousand cubic feet of natural gas.
Mineral interests
The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtu
Million British Thermal Units.

ii


MMcf
Million cubic feet of natural gas.
Net acres
The sum of the fractional working interest owned in gross acres.
Net royalty acres
Gross acreage multiplied by the average royalty interest.
Oil and natural gas properties
Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
Operator
The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
Play
A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.
Plugging and abandonment
Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
PUD
Proved undeveloped.
Productive well
A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
Prospect
A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed reserves
Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves
The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped reserves
Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Recompletion
The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
Reserves
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir
A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Resource play
A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.
Royalty interest
An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development or operations.
Spacing
The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.
Standardized measure
The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue.
Tight formation
A formation with low permeability that produces natural gas with very low flow rates for long periods of time.
Undeveloped acreage
Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

iii


Wellbore
The hole drilled by the bit that is equipped for oil or natural gas production on a completed well.
Working interest
An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
WTI
West Texas Intermediate.


iv


GLOSSARY OF CERTAIN OTHER TERMS
The following is a glossary of certain other terms used in this report:
Delaware Act
Delaware Revised Uniform Limited Partnership Act.
Diamondback
Diamondback Energy, Inc., a Delaware corporation.
EPA
U.S. Environmental Protection Agency.
Exchange Act
The Securities Exchange Act of 1934, as amended.
FERC
Federal Energy Regulatory Commission.
GAAP
Accounting principles generally accepted in the United States.
General partner
Viper Energy Partners GP LLC, a Delaware limited liability company; the general partner of the Partnership and a wholly-owned subsidiary of Diamondback.
Inception
September 18, 2013, the date Viper Energy Partners LLC was formed.
IPO
The partnership’s initial public offering of common units.
IRS
Internal Revenue Service.
LTIP
Viper Energy Partners LP Long Term Incentive Plan.
Operating Company
Viper Energy Partners LLC, a Delaware limited liability company and a consolidated subsidiary of Viper Energy Partners LP.
OSHA
Federal Occupational Safety and Health Act.
Partnership
Viper Energy Partners LP, a Delaware limited partnership.
Partnership agreement
The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018.
Predecessor
Viper Energy Partners LLC, a Delaware limited liability company, and a wholly-owned subsidiary of the Partnership.
Ryder Scott
Ryder Scott Company, L.P.
SEC
Securities and Exchange Commission.
Securities Act
The Securities Act of 1933, as amended.
Wells Fargo
Wells Fargo Bank, National Association.


v


CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this Annual Report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this Annual Report, including those detailed underItem 1A. Risk Factors” in this Annual Report, could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements.

Forward-looking statements may include statements about:

our ability to execute our business strategies;

the volatility of realized oil and natural gas prices;

the level of production on our properties;

regional supply and demand factors, delays or interruptions of production;

our ability to replace our oil and natural gas reserves;

our ability to identify, complete and integrate acquisitions of properties or businesses, including our recent acquisitions;

general economic, business or industry conditions;

competition in the oil and natural gas industry;

the ability of our operators to obtain capital or financing needed for development and exploration operations;

title defects in the properties in which we invest;

uncertainties with respect to identified drilling locations and estimates of reserves;

the availability or cost of rigs, equipment, raw materials, supplies, oilfield services or personnel;

restrictions on the use of water;

the availability of transportation facilities;

the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;

federal and state legislative and regulatory initiatives relating to hydraulic fracturing;

future operating results;

exploration and development drilling prospects, inventories, projects and programs;

operating hazards faced by our operators; and

the ability of our operators to keep pace with technological advancements.


vi


All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities laws. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.



vii


PART I

References in this Annual Report to “Viper Energy Partners LP Predecessor,” “our predecessor,” “we,” “our,” “us” or like terms when used for periods prior to June 17, 2014 refer to Viper Energy Partners LLC, which Diamondback Energy, Inc. (NasdaqGS: FANG) contributed to Viper Energy Partners LP in connection with Viper Energy Partners LP’s initial public offering of common units, which we refer to as our IPO, on June 23, 2014. When used for periods on and after June 17, 2014. references in this Annual Report to (i) “Viper Energy Partners,” “Viper,” “the Partnership,” “our partnership,” “we,” “our,” “us” or like terms refer to Viper Energy Partners LP individually and collectively with its subsidiary, Viper Energy Partners LLC, as the context requires; (ii) “our general partner” refers to Viper Energy Partners GP LLC, our general partner and a wholly owned subsidiary of Diamondback; and (iii) the “Operating Company” or “OpCo” refers to Viper Energy Partners LLC, and (iv) “Diamondback” refers collectively to Diamondback Energy, Inc. and its subsidiaries other than the Partnership and its subsidiary.

ITEMS 1 and 2.     BUSINESS AND PROPERTIES

Overview

We are a publicly traded Delaware limited partnership formed by Diamondback on February 27, 2014 to, among other things, own, acquire and exploit oil and natural gas properties in North America. We are currently focused on oil and natural gas properties in the Permian Basin and the Eagle Ford Shale. Prior to May 10, 2018, we were treated as a pass-through entity for federal income tax purposes. On May 10, 2018, we elected to be treated as a corporation for U.S. federal income tax purposes, which we refer to as the Tax Election.
Our primary business objective is to provide an attractive return to our unitholders by focusing on business results, maximizing distributions through organic growth and pursuing accretive growth opportunities through acquisitions of mineral, royalty, overriding royalty, net profits and similar interests from Diamondback and from third parties. Our initial assets consisted of mineral interests in oil and natural gas properties in the Permian Basin in West Texas, substantially all of which are leased to working interest owners who bear the costs of operation and development. Diamondback contributed these assets to us upon the closing of our IPO on June 23, 2014.

Like Diamondback, we are currently focused primarily on oil and natural gas properties in the Permian Basin, which is one of the oldest and most prolific producing basins in North America. The Permian Basin, which consists of approximately 85,000 square miles centered around Midland, Texas, has been a significant source of oil production since the 1920s. The Permian Basin is known to have a number of zones of oil and natural gas bearing rock throughout.

Our Properties

As of December 31, 2018, our assets consisted of mineral interests underlying 532,295 gross acres and 14,841 net royalty acres in the Permian Basin and Eagle Ford Shale. Diamondback is the operator of approximately 37% of this acreage. As of December 31, 2018, there were 1,127 vertical wells and 2,321 horizontal wells producing on this acreage. Net production during the fourth quarter of 2018 was approximately 20,191 net BOE/d and net production for the year ended December 31, 2018 averaged 17,275 BOE/d. For the years ended December 31, 2018, 2017 and 2016, royalty revenue generated from these mineral interests was $282.7 million, $160.2 million and $78.8 million, respectively.

The estimated proved oil and natural gas reserves of our assets, as of December 31, 2018, were 63,136 MBOE based on a reserve report prepared by Ryder Scott Company, L.P., or Ryder Scott, our independent reserve engineers. Of these reserves, approximately 72% were classified as proved developed producing reserves. Proved undeveloped, or PUD, reserves included in this estimate were from 183 gross horizontal well locations. As of December 31, 2018, our proved reserves were approximately 66% oil, 18% natural gas liquids and 16% natural gas.

As of December 31, 2018, our mineral interests entitle us to receive an average 2.79% royalty interest on all production from our approximately 532,295 gross acres with no additional future capital or operating expense required. The actual royalty percentage varies by lease and ranges from less than 1% to 25%. The average royalty percentage on a production basis can therefore vary over time depending on the relative amount of production from the various leases. In the Spanish Trail area of Midland County, Texas where the majority of the drilling activity has been, our average royalty interest on an acreage weighted basis is 21.1% in 15,398 gross acres and Diamondback is the operator of 64% of this acreage.


1


As of December 31, 2018, based on Diamondback’s evaluation of applicable geologic and engineering data with respect to the approximate 37% of our mineral interests for which it is the operator, Diamondback had identified approximately 201 potential economic horizontal drilling locations in multiple horizons in the Spanish Trail area and approximately 596 potential economic horizontal drilling locations in multiple horizons in the Pecos County area. We do not have potential (not involving proved reserves) drilling location information with respect to the portion of our properties not operated by Diamondback, although we believe that the portion of the Spanish Trail area in Midland County, Texas operated by others has very similar production characteristics to the portion operated by Diamondback.

In addition to our mineral interests, we own a minor equity interest in an entity that owns mineral, overriding royalty, net profits, leasehold and other similar interests. The equity interest is so minor that we have no influence over partnership operating and financial policies. Subsequent to the adoption of Accounting Standards Update 2016-01, we mark our investment in this equity interest to fair value.

Our Relationship with Diamondback

As of December 31, 2018, our general partner had a 100% general partner interest in us, and Diamondback owned 731,500 common units and all of our 72,418,500 outstanding Class B units, representing approximately 59% of our total units outstanding. Diamondback also owns and controls our general partner. We believe that the properties held by Diamondback include properties that have, or with additional development will have, production and reserves characteristics that could make them attractive for inclusion in our partnership. We believe Diamondback’s significant ownership in us will motivate it to offer additional mineral and other interests in oil and natural gas properties to us in the future, although Diamondback has no obligation to do so and may elect to dispose of mineral and other interests in such properties without offering us the opportunities to acquire them.

We believe Diamondback views our partnership as part of its growth strategy and that Diamondback will be incentivized to pursue acquisitions jointly with us in the future. However, Diamondback will regularly evaluate acquisitions and may elect to acquire properties without offering us the opportunity to participate in such transactions. Moreover, Diamondback may not be successful in identifying potential acquisitions. Diamondback is free to act in a manner that is beneficial to its interests without regard to ours, which may include electing not to present us with acquisition or disposition opportunities.

In addition, neither we, the Operating Company nor our general partner has any employees. Diamondback provides management, operating and administrative services to us and our general partner. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, each of which is included elsewhere in this report.

Business Strategies

Our primary business objective is to provide an attractive return to unitholders by focusing on business results, maximizing distributions through organic growth and pursuing accretive growth opportunities through acquisitions of mineral interests from Diamondback and from third parties. We intend to accomplish this objective by executing the following strategies:

Capitalize on the development of the properties underlying our mineral interests. Our assets primarily consist of mineral interests in the Permian Basin and the Eagle Ford Shale in Texas. We expect the production from our mineral interests to increase as Diamondback and our other operators drill and develop our acreage without cost to us.

Leverage our relationship with Diamondback to participate with it in acquisitions of mineral or other interests in producing properties from third parties and to increase the size and scope of our potential third-party acquisition targets. We intend to make opportunistic acquisitions of mineral interests that have substantial oil-weighted resource potential and organic growth potential. Diamondback was formed, in part, to acquire and develop oil and natural gas properties, some of which will likely meet our acquisition criteria. In addition, Diamondback’s executives have long histories of evaluating, pursuing and consummating oil and natural gas property acquisitions in North America. Through our relationships with Diamondback and its affiliates, we have access to their significant pool of management talent and industry relationships, which we believe provide us with a competitive advantage in pursuing potential third-party acquisition opportunities. We may have additional opportunities to work jointly with Diamondback to pursue certain acquisitions of mineral or other interests in oil and natural gas properties from third parties. For example, we and Diamondback may jointly pursue an acquisition where we would acquire mineral or other interests in properties and Diamondback would acquire the remaining working and revenue interests in such properties. We believe this arrangement may give us access to third-party acquisition opportunities that we would not otherwise be in a position to pursue.


2


Seek to acquire from Diamondback, from time to time, mineral or other interests in producing oil and natural gas properties that meet our acquisition criteria. Since our formation, we have acquired, and may have additional opportunities from time to time in the future to acquire, mineral or other interests in producing oil and natural gas properties directly from Diamondback. We believe Diamondback may be incentivized to sell properties to us, as doing so may enhance Diamondback’s economic returns by monetizing long-lived producing properties while potentially retaining a portion of the resulting cash flow through distributions on Diamondback’s limited partner interests in us. However, none of Diamondback or any of its affiliates is contractually obligated to offer or sell any interests in properties to us.

Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our primary business objective:

Oil rich resource base in one of North America’s leading resource plays. The majority of the acreage underlying our mineral interests is located in one of the most prolific oil plays in North America, the Permian Basin in West Texas. The majority of our current properties are well positioned in the core of both the Midland and Delaware Basins. Production on our properties for the year ended December 31, 2018 was approximately 70% oil, 15% natural gas liquids and 15% natural gas. As of December 31, 2018, our estimated net proved reserves were comprised of approximately 66% oil, 18% natural gas liquids and 16% natural gas.

Multi-year drilling inventory in one of North America’s leading oil resource plays. Diamondback, as the operator of approximately 37% of our acreage, has advised us that it has identified a multi-year inventory of potential drilling locations for our oil-weighted reserves from the acreage underlying our mineral interests. At an assumed price of $55.00 per Bbl WTI, Diamondback had identified approximately 201 potential economic horizontal locations on the acreage Diamondback operates in its Spanish Trail area in Midland County, Texas, based on Diamondback’s evaluation of applicable geologic and engineering data. These potential economic locations are in the Wolfcamp B, Lower Spraberry, Wolfcamp A, Middle Spraberry, Clearfork and Cline horizons. Of the 201 potential economic locations, 56 are located in the Clearfork and Cline horizons in which Diamondback has no horizontal tests on the acreage, however based on engineering and geologic evaluation Diamondback believes the horizons to have economic potential. Diamondback’s current potential horizontal location count is based on 660-foot spacing between wells in the Wolfcamp B horizon, the Lower Spraberry horizon and the Wolfcamp A horizon, 880-foot spacing between wells in the Middle Spraberry horizon, and 1,320-foot spacing in the Clearfork and Cline horizons. The ultimate inter-well spacing may vary from these distances due to different factors, which would result in a higher or lower location count.

Additionally, at the same assumed price of $55.00 per Bbl WTI, Diamondback had identified approximately 596 potential economic horizontal locations on the acreage Diamondback operates in Pecos County, Texas, based on Diamondback’s evaluation of applicable geologic and engineering data. These potential economic locations are in the Wolfcamp B, Third Bone Spring, Wolfcamp A and Second Bone Spring horizons. Of the 596 potential economic locations, 299 are located in the Wolfcamp A and Second Bone Springs horizons in which Diamondback has a significant number of wells across its acreage while the remaining 297 locations are in the Wolfcamp B and Third Bone Springs horizons in which Diamondback has a limited number of tests on its acreage. Diamondback’s current potential horizontal location count is based on 880-foot spacing between wells in the Wolfcamp A and Wolfcamp B horizons, and 1,320-foot spacing between wells in the Second Bone Spring and Third Bone Spring horizons. The ultimate inter-well spacing may vary from these distances due to different factors, which would result in a higher or lower location count.

These PUD locations, as assigned by Ryder Scott, are for direct offsets to producing wells. Based on various geologic and engineering parameters, we believe that the estimates assigned to these PUD locations are reasonable estimates for development locations on the remaining portion of our acreage. Additionally, we believe that there is similar potential for horizontal development on the portion of our acreage for which Diamondback is not the operator.


3


Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Reserves

Our historical reserve estimates as of December 31, 2018, 2017 and 2016 were prepared by Ryder Scott. A reserve audit is not the same as a financial audit and is less vigorous in nature than an independent reserve report where the independent reserve engineer determines the reserves on its own.

Ryder Scott is an independent petroleum engineering firm. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is a third-party engineering firm and does not own an interest in any of our properties and is not employed by us on a contingent basis.

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, 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. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2018 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. Approximately 90% of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. The remaining 10% of the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.

To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

Our petroleum engineers and geoscience professionals work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Permian Basin. Our internal technical team members met with our independent reserve engineers periodically during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. The Executive Vice President–Reservoir Engineering of our general partner is primarily responsible for overseeing the preparation of all of our reserve estimates. The Executive Vice President–Reservoir Engineering of our general partner is a petroleum engineer with over 30 years of reservoir and operations experience and our geoscience staff has an average of approximately 19 years of industry experience per person. Our technical staff uses historical information for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs.


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The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

review and verification of historical production data, which data is based on actual production as reported by our operators;

preparation of reserve estimates by the Executive Vice President–Reservoir Engineering of our general partner or under his direct supervision;

review by the Executive Vice President–Reservoir Engineering of our general partner of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;

direct reporting responsibilities by the Executive Vice President–Reservoir Engineering of our general partner to the Chief Executive Officer of our general partner;

verification of property ownership by our land department; and

no employee’s compensation is tied to the amount of reserves booked.

The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2018, 2017 and 2016 based on the reserve reports prepared by Ryder Scott. Each reserve report has been prepared in accordance with the rules and regulations of the SEC. All of our proved reserves included in the reserve reports are located in the continental United States.
 
 
December 31,
 
2018
 
2017
 
2016
Estimated proved developed reserves:
 
 
 
 
 
Oil (MBbls)
29,526

 
18,788

 
12,332

Natural gas (MMcf)
49,681

 
29,256

 
15,933

Natural gas liquids (MBbls)
7,965

 
4,536

 
3,247

Total (MBOE)
45,771

 
28,200

 
18,235

Estimated proved undeveloped reserves:
 
 
 
 
 
Oil (MBbls)
12,352

 
7,097

 
9,012

Natural gas (MMcf)
11,916

 
7,139

 
11,158

Natural gas liquids (MBbls)
3,027

 
1,759

 
2,329

Total (MBOE)
17,365

 
10,046

 
13,200

Estimated Net Proved Reserves:
 
 
 
 
 
Oil (MBbls)
41,878

 
25,885

 
21,344

Natural gas (MMcf)
61,597

 
36,395

 
27,091

Natural gas liquids (MBbls)
10,992

 
6,295

 
5,576

Total (MBOE)(1)
63,136

 
38,246

 
31,435

Percent proved developed
72
%
 
74
%
 
58
%
(1)
Estimates of reserves as of December 31, 2018, 2017 and 2016 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2018, 2017 and 2016, respectively, in accordance with SEC guidelines applicable to reserve estimates as of the end of such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

As of December 31, 2018, our proved developed reserves totaled 29,526 MBbls of oil, 49,681 MMcf of natural gas and 7,965 MBbls of natural gas liquids, for a total of 45,771 MBOE. Producing reserves were from 1,127 vertical wells and 2,321 horizontal wells, of which Diamondback was the operator of 296 vertical wells and 392 horizontal wells. The remaining 831 vertical wells and 1,929 horizontal wells were operated by various other companies.


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The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See “Item 1A. Risk Factors.” We have not filed any estimates of total, proved net oil or natural gas reserves with any federal authority or agency other than the SEC.

Proved Undeveloped Reserves

As of December 31, 2018, our PUD reserves totaled 12,352 MBbls of oil, 11,916 MMcf of natural gas and 3,027 MBbls of natural gas liquids, for a total of 17,365 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production. Our PUD reserves were from 183 horizontal wells, of which Diamondback is the operator of 152 horizontal wells and Concho Resources Inc., following its acquisition of RSP Permian, Inc. in a merger completed in July 2018, is the operator of the remaining wells. While there is a significant amount of activity by other operators, due to uncertainty of timing, development horizon, and other factors, no PUD locations attributable to such other operators were included in our reserve report. Of the horizontal locations, 20 are Wolfcamp B wells, 61 are Lower Spraberry wells, 11 are Middle Spraberry wells and 91 are Wolfcamp A wells.

All of our PUD drilling locations are scheduled to be drilled within five years from the date they were initially recorded. As of December 31, 2018, none of our total proved reserves were classified as proved developed non-producing.

Changes in PUDs that occurred during 2018 were primarily due to:

additions of 13,674 MBOE, primarily from 138 horizontal well locations attributable to extensions resulting from strategic drilling of wells to delineate our acreage position;

downgrade of PUDs into probable category of 1,161 MBOE for nine short lateral horizontal wells that are not expected to be drilled due to the lower price environment;

the conversion of approximately 5,930 MBOE attributable to PUDs into proved developed reserves;

acquisitions of approximately 506 MBOE; and

positive revisions of approximately 230 MBOE in PUDs primarily due to changes in type curves and realized prices.


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Oil and Natural Gas Production Prices and Production Costs

Production and Price History

We operate in one reportable segment engaged in the acquisition of oil and natural gas properties. For a description of our revenues, average sales prices and unit costs, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table sets forth information regarding the operators’ net production of oil, natural gas and natural gas liquids, all of which is from the Permian Basin and the Eagle Ford Shale in Texas, and certain price and cost information for each of the periods indicated:
 
Year Ended December 31,
 
2018
 
2017
 
2016
Production Data:
 
 
 
 
 
Oil (MBbls)
4,399

 
2,899

 
1,778

Natural gas (MMcf)
5,840

 
3,549

 
1,490

Natural gas liquids (MBbl)
933

 
533

 
328

Combined volumes (MBOE)
6,305

 
4,024

 
2,354

Daily combined volumes (BOE/d)
17,275

 
11,023

 
6,432

Average Prices:
 
 
 
 
 
Oil (per Bbl)
$
56.13

 
$
48.36

 
$
40.23

Natural gas (per Mcf)
2.22

 
2.62

 
2.08

Natural gas liquids (per Bbl)
24.41

 
20.02

 
12.84

Combined (per BOE)
44.83

 
39.81

 
33.49


Productive Wells

As of December 31, 2018, our operators owned a working interest in 3,448 productive wells located on the acreage in which we have a mineral interest. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

Acreage

The following table sets forth information as of December 31, 2018 relating to the gross and net royalty acreage of our mineral interests:
Basin
Gross Acreage
 
Net Royalty Acreage
Permian Basin
411,942
 
14,160
Eagle Ford Shale
120,353
 
681
Total acreage
532,295
 
14,841
     
Our net interest in production from our mineral interests is based on lease royalty terms which vary from property to property. Our interest in the majority of these properties is perpetual in nature, however approximately 11.7% of the net royalty acreage consists of over-riding royalty interests which may be subject to expiration. Net royalty acres are defined as gross acreage multiplied by the average royalty interest.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional mineral, royalty, overriding

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royalty, net profits and similar interests in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for these and other oil and natural gas properties. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Seasonal Nature of Business

Generally, demand for oil increases during the summer months and decreases during the winter months while natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for our operators in meeting well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.

Regulation

The following disclosure describes regulation more directly associated with operators of oil and natural gas properties, including our current operators, and other owners of working interests in oil and natural gas properties. To the extent we elect in the future to engage in the exploration, development and production of oil and natural gas properties, we would be directly subject to the same regulations described below. For purposes of this section, where applicable, references to “we,” “us,” and “our” refer to Viper Energy Partners LP to the extent the partnership were to acquire working interests in the future as well as to any operators of our properties, including our current operators.

Oil and natural gas operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases the cost of doing business.

Environmental Matters

Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas, and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. Liability under such laws and regulations is often strict (i.e., no showing of “fault” is required) and can be joint and several. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially and adversely affect our business and prospects.

Waste Handling

The Resource Conservation and Recovery Act, as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of the Resource Conservation and Recovery Act, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under the Resource Conservation and

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Recovery Act, such wastes may constitute “solid wastes” that are subject to the less stringent non-hazardous waste requirements. Moreover, the EPA or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste. It has until March 2019 to determine whether any revisions are necessary. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase the costs to manage and dispose of wastes.

Remediation of Hazardous Substances

The Comprehensive Environmental Response, Compensation and Liability Act, as amended, which we refer to as CERCLA or the “Superfund” law, and analogous state laws, generally impose liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” are subject to strict liability that, in some circumstances, may be joint and several for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.

Water Discharges

The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. On June 29, 2015, the EPA and the U.S. Army Corps of Engineers, or the Corps, jointly promulgated final rules redefining the scope of waters protected under the Clean Water Act. The rules are subject to ongoing litigation and have been stayed in more than half the States, including Texas. Also, on December 11, 2018, the EPA and the Corps released a proposed rule that would replace the 2015 rule, and significantly reduce the waters subject to federal regulation under the Clean Water Act. Such proposal is currently subject to public review and comment, after which additional legal challenges are anticipated. As a result of such recent developments, substantial uncertainty exists regarding the scope of waters protected under the Clean Water Act. To the extent the rule expands the range of properties subject to the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants, which regulations are discussed in more detail below under the caption “–Regulation of Hydraulic Fracturing.” Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

The Oil Pollution Act is the primary federal law for oil spill liability. The Oil Pollution Act contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that

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operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The Oil Pollution Act subjects owners of facilities to strict liability that, in some circumstances, may be joint and several for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

Non-compliance with the Clean Water Act or the Oil Pollution Act may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations.

Air Emissions

The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “–Regulation of Hydraulic Fracturing.” Also, on May 12, 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change

In December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. In May 2010, the EPA adopted regulations establishing new greenhouse gas emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA, the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their greenhouse gas emissions. The Court ruled, however, that the EPA may require installation of best available control technology for greenhouse gas emissions at sources otherwise subject to the PSD and Title V programs. On August 26, 2016, the EPA proposed changes needed to bring the EPA’s air permitting regulations in line with the Supreme Court’s decision on greenhouse gas permitting. The proposed rule was published in the Federal Register on October 3, 2016 and the public comment period closed on December 2, 2016.

Additionally, in September 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the U.S., including natural gas liquids fractionators and local natural gas distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded the greenhouse gas reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In October 2015, the EPA amended the greenhouse gas reporting rule to add the reporting of greenhouse gas emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines.

As a result of this continued regulatory focus, future greenhouse gas regulations of the oil and gas industry remain a possibility. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions.

At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties

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to cooperate and report actions to reduce greenhouse gas emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.

Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.

In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.

On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015.

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The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, President Trump directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017, the EPA published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. Also, on October 15, 2018, the EPA published a proposed rule to significantly reduce regulatory burdens imposed by the 2016 regulations, including, for example, reducing the monitoring frequency for fugitive emissions and revising the requirements for pneumatic pumps at well sites. The above standards, to the extent implemented, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions. We cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

Several states, including Texas, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted legislation, effective September 1, 2011, requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. The Texas Railroad Commission adopted rules and regulations implementing this legislation that apply to all wells for which the Texas Railroad Commission issues an initial drilling permit after February 1, 2012. The law requires that the well operator disclose the list of chemical ingredients subject to the requirements of OSHA for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Also, in May 2013, the Texas Railroad Commission adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The rules took effect in January 2014. Additionally, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. The disposal well rule amendments, which became effective on November 17, 2014, also clarify the Texas Railroad Commission’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Texas Railroad Commission has used this authority to deny permits for waste disposal wells.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material

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adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices.

Drilling and Production

The operations of our operators are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The states, and some counties and municipalities, in which our operators conduct business also regulate one or more of the following:

the location of wells;

the method of drilling and casing wells;

the timing of construction or drilling activities, including seasonal wildlife closures;

the rates of production or “allowables”;

the surface use and restoration of properties upon which wells are drilled;

the plugging and abandoning of wells; and

notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that our operators can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure our unitholders that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill.

Federal, state and local regulations provide detailed requirements for the plugging and abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas. Although the Corps does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

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Natural Gas Sales and Transportation

Historically, federal legislation and regulatory controls have affected the price and marketing of natural gas. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.” Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that our operators produce, as well as the revenues our operators receive for sales of natural gas and release of natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under FERC’s current regulatory regime, transmission services are provided on an open-access, non-discriminatory basis at cost-based rates or negotiated rates. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our operators’ costs of transporting gas to point-of-sale locations.

Oil Sales and Transportation

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to our operators to the same extent as to our or their competitors.

State Regulation

Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure our unitholders that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations our operators can drill.


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The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Employees

We do not have any employees. We are managed and operated by the board of directors and executive officers of our general partner. All of the employees that conduct our business, including our executive officers, are employed by Diamondback.

As of December 31, 2018, Diamondback had 711 full-time employees. None of Diamondback’s employees are represented by labor unions or covered by any collective bargaining agreements. Diamondback also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist its full-time employees. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, each of which is included elsewhere in this Annual Report.

Facilities

Our principal executive offices are located in Midland, Texas and are owned by Diamondback. We believe that these facilities are adequate for our current operations.

Availability of Partnership Reports

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available free of charge on the Investor Relations page of our website at www.viperenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.

ITEM 1A.     RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected. In that case, we might not be able to make distributions on our common units, the trading price of our common units could decline, and unitholders could lose all or part of their investment. Other risks are also described in “Items 1 and 2. Business and Properties” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Risks Related to Our Business

We may not have sufficient available cash to pay any quarterly distribution on our common units.

We may not have sufficient available cash each quarter to enable us to pay any distributions to our common unitholders. Furthermore, our partnership agreement does not require us to pay distributions on a quarterly basis or otherwise. The amount of cash we have to distribute each quarter principally depends upon the amount of royalty revenues we generate, which are dependent upon the volumes of production sold and the prices that our operators realize from the sale of such production. In addition, the actual amount of cash we will have to distribute each quarter under our cash distribution policy will be reduced by replacement capital expenditures, payments in respect of debt service and other contractual obligations and fixed charges and increases in reserves for future operating or capital needs that the board of directors may determine is appropriate.

The amount of cash we have available for distribution to holders of our units depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods in which we record net losses for financial accounting purposes and may be unable to make cash distributions during periods in which we record net income.


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The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and is directly dependent on the performance of our business. We do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could make no distribution with respect to any particular quarter.

Our future business performance may be volatile, and our cash flows may be unstable. We do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero.

The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to make any distributions at all.

The board of directors of our general partner has adopted a cash distribution policy pursuant to which we distribute an amount equal to the available cash we generate each quarter to our unitholders. However, the board of directors of our general partner may change such policy at any time at its discretion and could elect not to pay distributions for one or more quarters.

In addition, our partnership agreement does not require us to pay any distributions at all. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of Diamondback to the detriment of our common unitholders.

The volatility of oil and natural gas prices, and particularly the ongoing decline in those prices, due to factors beyond our control greatly affects our financial condition, results of operations and cash available for distribution.

Our revenues, operating results, cash available for distribution and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

the domestic and foreign supply of oil and natural gas;

the level of prices and expectations about future prices of oil and natural gas;

the level of global oil and natural gas exploration and production;

the cost of exploring for, developing, producing and delivering oil and natural gas;

the price and quantity of foreign imports;

political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;

the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

speculative trading in crude oil and natural gas derivative contracts;

the level of consumer product demand;

weather conditions and other natural disasters;

risks associated with operating drilling rigs;

technological advances affecting energy consumption;

the price and availability of alternative fuels;

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domestic and foreign governmental regulations and taxes;

the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;

the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and

overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. During the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI, has ranged from a low of $26.19 per barrel, or Bbl, in February 2016 to a high of $107.95 per Bbl in June 2014. The Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. During 2018, WTI prices ranged from $44.48 to $77.41 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.49 to $6.24 per MMBtu. On January 28, 2019, the WTI posted price for crude oil was $51.79 per Bbl and the Henry Hub spot market price of natural gas was $3.05 per MMBtu. In response to recent declines in commodity prices, many producers have reduced their capital expenditure budgets. If the prices of oil and natural gas remain at current levels or decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our credit agreement, which may be determined at the discretion of our lenders.

In addition, lower oil and natural gas prices may also reduce the amount of oil and natural gas that can be produced economically by our operators. This may result in having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if production estimates change or exploration or development results deteriorate, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities.

We do not enter into hedging arrangements with respect to the oil and natural gas production from our properties, and we will be exposed to the impact of decreases in the price of oil and natural gas.

We have not entered into hedging arrangements to establish, in advance, a price for the sale of the oil and natural gas produced from our properties, and we do not intend to enter into such arrangements in the future. As a result, we may realize the benefit of any short-term increase in the price of oil and natural gas, but we will not be protected against decreases in price, and if the price of oil and natural gas continues at current levels or decreases further, our business, results of operations and cash available for distribution may be materially adversely affected.

We depend on two operators for substantially all of the development and production on the properties underlying our mineral interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of either operator to adequately and efficiently develop and operate our acreage could have an adverse effect on our expected growth and our results of operations.

Substantially all of our assets are mineral interests from which we derive royalty income. For the year ended December 31, 2018, we received approximately 59% and 16% of our royalty revenue from Diamondback and Concho Resources, Inc, respectively. The failure of Diamondback or Concho Resources, Inc. to adequately or efficiently perform operations or an operator’s failure to act in ways that are in our best interests could reduce production and revenues. Further, none of the operators of our properties are obligated to undertake any development activities, so any development and production activities will be subject to their reasonable discretion. Due to the current commodity price environment, both Diamondback and Concho Resources, Inc. have expressed an intent to drill and complete fewer wells on our acreage than we previously anticipated. The level, success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that will be largely outside of our control, including:

commodity prices;

the timing and amount of capital expenditures by our operators, which could be significantly more than anticipated;


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the ability of our operators to access capital;

the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;

the operators’ expertise, operating efficiency and financial resources;

approval of other participants in drilling wells;

the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;

the selection of technology;

the selection of counterparties for the sale of production; and

the rate of production of the reserves.

The operators may elect not to undertake development activities, or may undertake such activities in an unanticipated fashion, which may result in significant fluctuations in our royalty revenues and cash available for distribution to our unitholders. If reductions in production by the operators are implemented on our properties and sustained, our revenues may also be substantially affected. Additionally, if an operator were to experience financial difficulty, the operator might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on us.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.

Approximately 28% of our total estimated proved reserves as of December 31, 2018 were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or further decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

We may not be able to terminate our leases if any of our operators declare bankruptcy, and we may experience delays and be unable to replace operators that do not make royalty payments.

A failure on the part of the operators to make royalty payments gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to bankruptcy proceedings that could prevent the execution of a new lease or the assignment of the existing lease to another operator. In addition, if we enter into a new lease, the replacement operator may not achieve the same levels of production or sell oil or natural gas at the same price as the operator it replaced.

Our producing properties are primarily located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.

Our producing properties are currently geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature

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of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

In addition to the geographic concentration of our producing properties described above, as of December 31, 2018, all of our proved reserves were attributable to the Midland and Delaware basins and the Eagle Ford Shale. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

Our future success depends on finding, developing or acquiring additional reserves.

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that successful exploration or development activities are conducted on our properties or we acquire properties containing proved reserves, or both. To increase reserves and production, we would need to undertake development, exploration and other replacement activities or use third parties to accomplish these activities. Substantial capital expenditures will be necessary for the development, production, exploration and acquisition of oil and natural gas reserves. Neither we nor our third-party operators may have sufficient resources to acquire additional reserves or to undertake exploration, development, production or other replacement activities, such activities may not result in significant additional reserves and efforts to drill productive wells at low finding and development costs may be unsuccessful. In addition, we do not expect to retain cash from our operations for replacement capital expenditures. Furthermore, although our revenues and cash available for distribution may increase if prevailing oil and natural gas prices increase significantly, finding costs for additional reserves could also increase.

Our failure to successfully identify, complete and integrate acquisitions of properties or businesses could slow our growth and adversely affect our results of operations and cash available for distribution.

There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including:

recoverable reserves;

future oil and natural gas prices and their applicable differentials;

operating costs; and

potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Unless our operators further develop our existing properties, we will depend on acquisitions to grow our reserves, production and cash flow.

Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently hold properties, which could result in unforeseen operating difficulties. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

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No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations and cash available for distribution. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations and cash available for distribution.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Project areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.

Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. During the year ended December 31, 2018, Diamondback, which is the operator for approximately 37% of the acreage associated with our properties, drilled a total of 104 gross wells, of which 15 wells were in various stages of completion. If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations and cash available for distribution may be materially affected.

Our method of accounting for investments in oil and natural gas properties resulted in an impairment of asset value for the year ended December 31, 2016 and may result in further impairments in future periods.

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $9.33, $10.07 and $12.67 for the years ended December 31, 2018, 2017 and 2016, respectively.

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. We use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues.

An impairment on proved oil and natural gas properties of $47.5 million was recorded for the year ended December 31, 2016. No impairments on proved oil and natural gas properties were recorded for the years ended December 31, 2018 and 2017. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations–Critical Accounting Policies and Estimates–Method of Accounting for Oil and Natural Gas Properties.” If the prices of oil and natural gas decline, we may be required to write down the value of our oil and natural gas properties in the future, which could negatively affect our results of operations.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

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Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our historical estimates of proved reserves and related valuations as of December 31, 2018, 2017 and 2016, were prepared by Ryder Scott, an independent petroleum engineering firm, which conducted a well-by-well review of all our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that we ultimately recover being different from our reserve estimates. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage.

The estimates of reserves as of December 31, 2018, 2017 and 2016 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2018, 2017 and 2016, respectively, in accordance with the SEC guidelines applicable to reserve estimates for such period.

SEC rules could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe because they have become uneconomic or otherwise.

Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, financial condition and cash available for distribution.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit and the European, Asian and the U.S. markets contribute to economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, volatility in consumer confidence and job markets, may result in an economic slowdown or recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which oil, natural gas and natural gas liquids from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately adversely impact our results of operations, financial condition and cash available for distribution.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.


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We rely on a few key individuals whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of individuals. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including the Chief Executive Officer of our general partner, Travis D. Stice, could disrupt our business. Diamondback has employment agreements with Travis D. Stice and Teresa L. Dick, the Chief Financial Officer of our general partner, and certain other employees of our general partner which contain restrictions on competition with the business or operations of Diamondback and its subsidiaries until the later of the termination of their employment with or other affiliation with such entities and for a period of six months thereafter. However, as a practical matter, such employment agreements may not assure the retention of Diamondback’s employees. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Our credit agreement has restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.

The operating and financial restrictions and covenants in our credit agreement and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions to our unitholders. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our credit agreement that are not cured or waived within the appropriate time periods provided in our credit agreement, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions to our unitholders will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit agreement are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit agreement, the lenders could seek to foreclose on our assets.

Our credit agreement allows us to borrow in an amount up to the borrowing base, which is based on our oil and natural gas reserves and other factors as determined semi-annually by our lenders in their sole discretion. As of December 31, 2018, the borrowing base was set at $555.0 million, and we had $411.0 million of outstanding borrowings and $144.0 million available for future borrowings under our revolving credit facility. A decline in commodity prices could result in a redetermination that lowers our borrowing base at that time and, in such case, we could be required to repay any indebtedness outstanding in excess of the borrowing base. If we are unable to repay any borrowings in excess of a decreased borrowing base, we would be in default and no longer able to make any distributions to our unitholders.

Loss of our information and computer systems could adversely affect our business.

We are dependent on our information systems and computer based programs. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.


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Risks Related to Operators and Other Working Interest Owners

The following describes risks that may directly affect our business and operations to the extent we elect in the future to engage in the exploration, development and production of oil and natural gas properties. In addition, any operators of our properties, including our current operators, are subject to the risks and uncertainties described below, and, as the owner of mineral interests, we are indirectly exposed to the same risks and uncertainties. For purposes of this section, where applicable, references to “we,” “us” and “our” refer to Viper Energy Partners LP to the extent the partnership were to acquire working interests in the future, as well as to any operators of our properties, including the current operators.

If a significant portion of any future net leasehold acreage is undeveloped, and that acreage is not ultimately developed or does not become commercially productive, we could lose rights under these leases, and any such events could have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our financial condition, results of operations and cash available for distribution.

To the extent we acquire working interests in the future, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves, we could lose our rights under those leases if we do not timely develop such acreage. In addition, if we are required under any such oil and natural gas leases to drill wells that are commercially productive and we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our financial condition, results of operations and cash available for distribution may be highly dependent on successfully developing our undeveloped leasehold acreage.

Development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. To the extent we acquire working interests in the future, we will not be able to assure our unitholders that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure our unitholders that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

If we acquire working interests in the future and we are unable to fund our capital requirements, we may be required to curtail operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, results of operations and cash available for distribution. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.

We may incur losses as a result of title defects in the properties in which we invest.

If we acquire working interests in the future, when acquiring oil and natural gas leases, we may not elect to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we may rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations, financial condition and cash available for distribution.

Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of leasehold rights in properties in which we hold an interest, our business, results of operations and cash available for distribution may be adversely affected.


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Identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

To the extent we acquire working interests in the future, our ability to drill and develop identified potential drilling locations will depend on a number of uncertainties, including the availability of capital, construction of infrastructure, regulatory changes and approvals, costs, drilling results, the availability of water and weather conditions. Further, identified potential drilling locations are typically in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. We will not be able to predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable or whether wells drilled on different spacing assumptions will produce at materially different rates. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill wells that we identify as dry holes in current and future drilling locations, our drilling success rate may decline and materially harm our business.

We will not be able to assure our unitholders that the analogies drawn from available data from wells drilled, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations we identify will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those identified, which could adversely affect our business.

For information on Diamondback’s identified potential drilling locations, see “Items 1 and 2. Business and Properties.”

Acreage must be drilled before lease expiration, generally within three to five years, to hold the acreage by production. The failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. To the extent we acquire working interests in the future, the cost to renew our leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. Any such losses of leases could materially and adversely affect the growth of our financial condition, results of operations and cash available for distribution.

The inability of one or more of our customers to meet their obligations may adversely affect our financial condition, results of operations and cash available for distribution.

To the extent we acquire working interests in the future, we may have exposure to credit risk through receivables from joint interest owners on properties we operate and receivables from purchasers of our oil and natural gas production.

Joint interest receivables will arise from billing entities that own partial interests in any wells we operate. These entities will typically participate in our wells primarily based on their ownership in leases on which we wish to drill. We will generally be unable to control which co-owners participate in our wells.

We also may be subject to credit risk due to the concentration of oil and natural gas receivables with several significant customers. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Current economic circumstances may further increase these risks. Generally, customers are not required to post collateral. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial condition, results of operations and cash available for distribution.


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To the extent we depend upon certain significant purchasers for the sale of most of our oil and natural gas production, the loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce and adversely affect our results of operations and cash available for distribution.

To the extent we acquire working interests in the future, the availability of a ready market for any oil and natural gas we produce will depend on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of natural gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of natural gas sold in interstate commerce. In addition, to the extent we depend upon certain significant purchasers for the sale of most of our oil and natural gas production, the loss of one or more of such purchasers, or their failure or inability to meet their obligations to us, could adversely affect our results of operations and cash available for distribution. We cannot assure our unitholders that we will have ready access to suitable markets for our oil and natural gas production if we acquire working interests in the future.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. To the extent we acquire working interests in the future, in accordance with customary industry practice, we will rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we may not have long-term contracts securing the use of our rigs, and the operator of those rigs may choose to cease providing services to us. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could adversely affect our financial condition, results of operations and cash available for distribution.

Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash available for distribution.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Parts of Texas have experienced drought conditions in the past years. As a result, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. To the extent we acquire working interests in the future, if we are unable to obtain water to use in our operations from local sources, or we are unable to effectively utilize flowback water, we may be unable to economically drill for or produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash available for distribution.

The results of our exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.

To the extent we acquire working interests in the future, our operations will involve utilizing the latest drilling and completion techniques. Risks that we will face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we will face while completing wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in identified vertical drilling locations. Furthermore, certain of the new techniques we may adopt, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. The results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we will be less able to predict future drilling results in these areas.


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Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline.

The marketability of oil and natural gas production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, our operations could be interrupted and our results of operations and cash available for distribution could be adversely affected.

To the extent we acquire working interests in the future, the marketability of our oil and natural gas production will depend in part upon the availability, proximity and capacity of transportation facilities, including gathering systems, trucks and pipelines, owned by third parties. We may not control these third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. For example, on certain occasions, our operators have experienced high line pressure at their tank batteries with occasional flaring due to the inability of the gas gathering systems to support the increased production of natural gas in the Permian Basin. If we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our control, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, could adversely affect our financial condition, results of operations and cash available for distribution.

Our operations will be subject to various governmental laws and regulations which require compliance that can be burdensome and expensive and could expose us to significant liabilities, which could adversely affect our cash available for distribution.

To the extent we acquire working interests in the future, our oil and natural gas operations will be subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and regulations impose strict requirements for water and air pollution control and solid waste management.

Laws and regulations governing exploration and production may also affect production levels. To the extent we acquire working interests in the future, we will be required to comply with federal and state laws and regulations governing conservation matters, including: provisions related to the unitization or pooling of the oil and natural gas properties; the establishment of maximum rates of production from wells; the spacing of wells; the plugging and abandonment of wells; and the removal of related production equipment. Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increase capital costs on the part of operators and third party downstream natural gas transporters.

If we acquire working interests in the future, we will also be required to comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of such pipelines and with federal policies related to the use of interstate capacity.


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Significant expenditures may be required to comply with the governmental laws and regulations described above. Even if federal regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term, and at the state and local levels. See “Items 1 and 2. Business and Properties—Regulation” for a description of the laws and regulations that affect our operators and that, to the extent we acquire working interests in the future, will affect us. These and other potential regulations could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business, any of which could have a material adverse effect on the amount of cash available for distribution to our unitholders.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.

In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.

On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration.

Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

Several states, including Texas, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For a more detailed discussion of state and local laws and initiatives concerning hydraulic fracturing, see “Items 1 and 2. Business and Properties–Regulation–Regulation of Hydraulic Fracturing.”

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws

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could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

To the extent we acquire working interests in the future, we may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may, among other things: (i) require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing and other operations; (ii) regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; (iii) limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; (iv) require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or (v) impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental and/or unpermitted spills or releases from our operations could expose us to significant liabilities, penalties and other sanctions under applicable laws. Moreover, public interest in the protection of the environment has tended to increase over time. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

To the extent we acquire working interests in the future, our operations may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

If we acquire working interests in the future, the regulation of greenhouse gas emissions could result in increased operating costs and reduced demand for the oil and natural gas we produce.

In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. The EPA has finalized a series of greenhouse gas monitoring, reporting and emissions control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of the states have already taken measures to reduce emissions of greenhouse gases primarily through the development of greenhouse gas emission

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inventories and/or regional greenhouse gas cap-and-trade programs. While we are subject to certain federal greenhouse gas monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of existing and proposed greenhouse gas rules and regulations, see “Items 1 and 2. Business and Properties–Regulation–Environmental Regulation-Climate Change.”

At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.

Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

Legislation or regulatory initiatives intended to address seismic activity could restrict drilling and production activities of our operators, as well as their ability to dispose of produced water gathered from such activities.
State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend

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or terminate the permit application or existing operating permit for that well. The Commission has used this authority to deny permits for waste disposal wells.
Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may adversely affect our business, financial condition, results of operations and cash available for distribution.

If we acquire working interests in the future, our drilling activities will be subject to many risks. For example, we will not be able to assure our unitholders that wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

unusual or unexpected geological formations;

loss of drilling fluid circulation;

title problems;

facility or equipment malfunctions;

unexpected operational events;

shortages or delivery delays of equipment and services;

compliance with environmental and other governmental requirements; and

adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and cash available for distribution to our unitholders may be adversely affected.

Operating hazards and uninsured risks may result in substantial losses and could adversely affect our results of operations and cash available for distribution.

To the extent we acquire working interests in the future, our operations will be subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks and ruptures or discharges of toxic gases. In addition, our operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.

We would endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods, which include pressure pumping and hydraulic fracturing, drilling and cementing services and tubular goods for surface, intermediate and production casing. Under agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (i) our vendors would generally assume all responsibility for control and removal of pollution or contamination which originates above the surface of the land and is directly associated with such vendors’ equipment while in their control and (ii) we would generally assume the responsibility for control and removal of all other pollution or contamination which may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas or other substances, as well as the use or disposition of all

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drilling fluids. In addition, we may agree to indemnify our vendors for loss or destruction of vendor-owned property that occurs in the well hole (except for damage that occurs when a vendor is performing work on a footage, rather than day work, basis) or as a result of the use of equipment, certain corrosive fluids, additives, chemicals or proppants. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into contractual arrangements with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition, results of operation and cash available for distribution.

In accordance with what we believe to be customary industry practice, we would expect to maintain insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash available for distribution. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.

We may not have coverage if we are unaware of a sudden and accidental pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We do not have, and do not intend to have, coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure our unitholders that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash available for distribution.

If we acquire working interests in the future, we may operate in areas of high industry activity, which may make it difficult to hire, train or retain qualified personnel needed to manage and operate our assets.

If we acquire working interests in the future, our operations and drilling activity will likely be concentrated in the Permian Basin, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.

Any delay or inability to secure the personnel necessary to continue or complete development activities could lead to a reduction in production volumes. Any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

To the extent we acquire working interests in the future, we will rely on 2-D and 3-D seismic data. Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. To the extent we acquire working interests in the future, as others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations and cash available for distribution could be materially and adversely affected.

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Increased costs of capital could adversely affect our business.

Our business and operating results could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and, to the extent we acquire working interests in the future, our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities. For example, the oil and natural gas industry depends on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems, networks, and those of its vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of its business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. We do not maintain specialized insurance for possible liability resulting from a cyberattack on our assets that may shut down all or part of our business.
Risks Inherent in an Investment in Us

Diamondback owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Diamondback, have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our unitholders.

Diamondback owns and controls our general partner and appoints all of the directors of our general partner. All of the executive officers and certain of the directors of our general partner are also officers and/or directors of Diamondback. Although our general partner has a duty to manage us in a manner that it believes is not adverse to our interest, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Diamondback. Therefore, conflicts of interest may arise between Diamondback or any of its affiliates, including our general partner, on the one hand, and us or any of our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:

Our general partner is allowed to take into account the interests of parties other than us, such as Diamondback, in exercising certain rights under our partnership agreement.

Neither our partnership agreement nor any other agreement requires Diamondback to pursue a business strategy that favors us.

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Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders.

Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf.

Our general partner intends to limit its liability regarding our contractual and other obligations.

Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

Our general partner controls the enforcement of obligations that it and its affiliates owe to us.

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

In addition, Diamondback or its affiliates, may compete with us.

The board of directors of our general partner has adopted a policy pursuant to which the Operating Company will distribute all of the available cash it generates each quarter and we, in turn, will distribute all of the available cash we receive from the Operating Company to our common unitholders. This policy could limit our ability to grow and make acquisitions.

As a result of our cash distribution policy, we have limited cash available to reinvest in our business or to fund acquisitions, and we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. As such, to the extent we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.

To the extent we issue additional units in connection with any acquisitions or growth capital expenditures or as in-kind distributions, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the available cash that we have to distribute to our unitholders. Further, following the Tax Election on May 10, 2018, available cash for each quarter will also be reduced for cash needed for income taxes payable by us, if any.

Neither we nor our general partner have any employees, and we rely solely on the employees of Diamondback to manage our business. The management team of Diamondback, which includes the individuals who manage us, also perform similar services for Diamondback and own and operate Diamondback’s assets, and thus are not solely focused on our business.

Neither we nor our general partner have any employees and we rely solely on Diamondback to operate our assets and perform other management, administrative and operating services for us and our general partner. Diamondback provides similar activities with respect to its own assets and operations. Because Diamondback provides services to us that are similar to those performed for itself, Diamondback may not have sufficient human, technical and other resources to provide those services at a level that Diamondback would be able to provide to us if it were solely focused on our business and operations. Diamondback may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to Diamondback’s interests. There is no requirement that Diamondback favor us over itself in providing its services. If the employees of Diamondback and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.


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Our partnership agreement replaces our general partner’s fiduciary duties to our unitholders.

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

how to allocate business opportunities among us and its affiliates;

whether to exercise its call right;

how to exercise its voting rights with respect to the units it owns;

whether to exercise its registration rights; and

whether or not to consent to any merger or consolidation of the partnership or any amendment to the partnership agreement.

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above.

Our partnership agreement restricts the remedies available to holders of our units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is generally required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

our general partner and its executive officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct in which our general partner or its executive officers or directors engaged in bad faith, willful misconduct or fraud or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and

our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction, even a transaction with an affiliate or the resolution of a conflict of interest, is:

approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our general partner is permitted to act in its sole discretion, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.


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Diamondback and other affiliates of our general partner may compete with us.

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than acting as our general partner, engaging in activities incidental to its ownership interest in us and providing management, advisory and administrative services to its affiliates or to other persons. However, affiliates of our general partner, including Diamondback, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, Diamondback may compete with us for investment opportunities and may own an interest in entities that compete with us. Further, Diamondback and its affiliates, may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets.

Diamondback is an established participant in the oil and natural gas industry and has resources greater than ours, which factors may make it more difficult for us to compete with Diamondback with respect to commercial activities as well as for potential acquisitions. As a result, competition from Diamondback and its affiliates could adversely impact our results of operations and cash available for distribution to our common unitholders.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors, and Diamondback. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

Holders of our units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by Diamondback, as a result of it owning our general partner, and not by our unitholders. Unlike publicly traded corporations, we do not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if holders of our units are dissatisfied, they cannot initially remove our general partner without its consent.

If our unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove our general partner. Unitholders will be unable to remove our general partner without its consent because affiliates of our general partner own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding units, voting as a single class, is required to remove our general partner. As of December 31, 2018, Diamondback owned 59% of our total units outstanding.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our units (other than our general partner and its affiliates and permitted transferees).

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, may not vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our unitholders to influence the manner or direction of management.


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Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. The amount and timing of such reimbursements will be determined by our general partner.

Prior to making any distribution to its unitholders, including us, the Operating Company will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner will determine the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available for distribution from the Operating Company to us and from us to our common unitholders.

At the time of our IPO, we and our general partner entered into an advisory services agreement with Wexford Capital LP, or Wexford, pursuant to which Wexford agreed to provide general finance and advisory services. Any fee paid would reduce the amount of cash available for distribution to our unitholders. We paid no amounts to Wexford under the advisory services agreement during 2017 and 2018. This agreement was terminated on November 12, 2018 with an effective date of December 31, 2018. In addition, we have entered into a tax sharing agreement with Diamondback pursuant to which we are required to reimburse Diamondback for our share of state and local income and other taxes borne by Diamondback as a result of our results being included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on the closing date of our IPO. No amounts have been paid to Diamondback under the tax sharing agreement.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partner to transfer its membership interests in our general partner to a third party. After any such transfer, the new member or members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with its own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the unitholders.

Common unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.

Under certain circumstances, common unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner.

Our general partner has a call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates (including Diamondback) own more than 80% of the units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a

36


tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. The common units and Class B units are considered limited partner interests of a single class for these provisions. As of December 31, 2018, Diamondback owned 59% of our total units outstanding.

We may issue additional common units and other equity interests without unitholder approval, which would dilute existing unitholder ownership interests.

Under our partnership agreement, we are authorized to issue an unlimited number of additional interests, including common units, without a vote of the unitholders. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

the proportionate ownership interest of unitholders in us immediately prior to the issuance will decrease;

the amount of cash distributions on each common unit may decrease;

the ratio of our taxable income to distributions may increase;

the relative voting strength of each previously outstanding common unit may be diminished; and

the market price of the common units may decline.

There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank may (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets.

As of December 31, 2018, we had 51,653,956 common units and 72,418,500 Class B units outstanding. All of the Class B units are owned by Diamondback and Class B units must be redeemed (together with an equal number of units of the Operating Company, or the OpCo units) for common units prior to their sale to any person or entity not affiliated with Diamondback. Sales by holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have provided registration rights to Diamondback. Pursuant to these registration rights, we have registered, under the Securities Act, all of the common units owned by Diamondback for resale (including common units issuable in respect of the Class B units and the OpCo units). Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any common units that they hold.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Diamondback is a publicly traded corporation and has developed a system of internal controls for compliance with public reporting requirements. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded partnership. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. Any failure to maintain effective internal controls, or difficulties encountered in

37


implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

Nasdaq does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

Our common units are listed on the Nasdaq Global Select Market. Because we are a publicly traded partnership, Nasdaq does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to stockholders of certain corporations that are subject to all of Nasdaq’s corporate governance requirements.

Our partnership agreement includes exclusive forum, venue and jurisdiction provisions. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. Our partnership agreement also provides that any unitholder bringing an unsuccessful action will be obligated to reimburse us for any costs we have incurred in connection with such unsuccessful action.

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees. In addition, if any person brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. If a dispute were to arise between a limited partner and us or our officers, directors or employees, the limited partner may be required to pursue its legal remedies in Delaware which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers.

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to permit the general partner to redeem the units of certain unitholders.

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the U.S. federal income tax status and/or the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to permit our general partner to redeem the units held by any person (i) whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates chargeable to our customers, (ii) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (iii) who fails to comply with the procedures established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.


38


We are treated as a corporation for U.S. federal income tax purposes and our cash available for distribution to our unitholders may be substantially reduced.
We are a Delaware limited partnership and, prior to May 10, 2018, we were treated as a pass-through entity for federal income tax purposes. On May 10, 2018, we elected to be treated as a corporation for U.S. federal income tax purposes. As a result, we are now subject to tax as a corporation at the corporate tax rate of 21%. Distributions on our common units will be treated as distributions on corporate stock for U.S. federal income tax purposes, and taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits). While we do not expect to have any taxable income in the next four years due to an agreement between Diamondback and us to specially allocate to Diamondback priority allocations of $300 million of the Operating Company’s income and gains over losses and deductions (but before depletion), there’s no guarantee that we will not have any taxable income as a result of our equity interests in the Operating Company. Because an entity-level tax is imposed on us due to our status as a corporation for U.S. federal income tax purposes, our distributable cash flow may be substantially reduced by our tax liabilities.
Recently enacted U.S. tax legislation as well as future U.S. tax legislations may adversely affect our business, results of operations, financial condition and cash flow.
On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act, or the Tax Act, that makes significant changes to U.S. federal income tax laws. Among other changes, the Tax Act contains significant changes to corporate taxation, including (i) a reduction of the corporate tax rate from a top marginal rate of 35% to a flat rate of 21%, (ii) a new limitation on the deductibility of interest expense, (iii) a limitation on the deduction for net operating losses to 80% of current year taxable income and elimination of net operating loss carrybacks, in each case, for losses arising in taxable years beginning after December 31, 2017 (though any such net operating losses may be carried forward indefinitely), and (iv) a repeal of the domestic production activities deduction. There may be other material adverse effects resulting from the Tax Act that we have not identified and that could have an adverse effect on our business, results of operations, financial condition and cash flow.
ITEM 1B.     UNRESOLVED STAFF COMMENTS

None.

ITEM 3.     LEGAL PROCEEDINGS

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

ITEM 4.     MINE SAFETY DISCLOSURES

Not applicable.


39


PART II
ITEM 5.     MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information and Cash Distributions to Unitholders

Our common units are listed on the Nasdaq Global Select Market under the symbol “VNOM.” Our common units began trading on June 18, 2014 at an initial public offering price of $26.00 per common unit. The following table shows the low and high sales price per common unit, as reported by the Nasdaq Global Select Market, for the periods indicated:
Period:
High
 
Low
 
Cash Distributions per Common Unit(1)
2018
 
 
 
 
 
1st Quarter
$
26.19

 
$
21.46

 
$
0.480

2nd Quarter
$
33.63

 
$
24.59

 
$
0.600

3rd Quarter
$
43.25

 
$
29.86

 
$
0.580

4th Quarter(2)
$
44.00

 
$
22.76

 
$
0.510

2017
 
 
 
 
 
1st Quarter
$
19.38

 
$
15.37

 
$
0.302

2nd Quarter
$
18.63

 
$
15.19

 
$
0.332

3rd Quarter
$
18.98

 
$
14.76

 
$
0.337

4th Quarter
$
24.00

 
$
18.02

 
$
0.460

(1)
Distributions are shown for the quarter in which they were generated.
(2)
The Q4 2018 distribution is payable on February 25, 2019 to unitholders of record at the close of business on February 19, 2019.

There were two holders of record of our common units on January 31, 2019.

Cash Distribution Policy

The board of directors of our general partner has adopted a policy pursuant to which the Operating Company distributes all of the available cash it generates in each quarter to its unitholders (including us), and pursuant to which we in turn distribute all of the available cash we receive from the Operating Company to our common unitholders. Our available cash, and the available cash of the Operating Company, for each quarter is determined by the board of directors of our general partner following the end of such quarter. We expect that the Operating Company’s available cash for each quarter will generally equal its Adjusted EBITDA for the 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 our general partner deems necessary or appropriate, if any, and that our available cash for each quarter will generally equal our Adjusted EBITDA (which is our proportional share of the available cash of the Operating Company for the quarter), less, as a result of the Tax Election, cash needed and for the payment of income taxes by us, if any, and the preferred distribution.

We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The board of directors of our general partner may change our distribution policy at any time. Our partnership agreement does not require us to pay distributions to our common unitholders on a quarterly or other basis.

Recent Sales of Unregistered Securities

As previously reported, in connection with the Tax Election and related recapitalization transaction, (i) Viper issued 73,150,000 Class B units and (ii) the Operating Company issued 73,150,000 OpCo units, in each case, to Diamondback pursuant to the terms of the recapitalization agreement in exchange for the tender by Diamondback of the 73,150,000 common units owned by Diamondback to Viper. This exchange, the terms of which are described in more detail in the Introductory Note to the Current Report on Form 8-K, filed with the SEC on May 15, 2018 and incorporated herein by reference, occurred on May 9, 2018. In addition, on May 10, 2018, Viper issued 731,500 common units to Diamondback in exchange for 731,500 Class B units and 731,500 OpCo units, the terms of which transaction are also described in the Introductory Note referenced above and incorporated herein by reference. The issuance of the foregoing units was exempt from the registration requirements of the Securities Act of

40


1933, as amended, or the “Securities Act”, in reliance upon Section 4(a)(2) of the Securities Act and/or Regulation D promulgated thereunder.
Repurchases of Equity Securities

None.

ITEM 6.     SELECTED FINANCIAL DATA

This section presents our selected historical consolidated financial data. The selected historical consolidated financial data presented below is not intended to replace our historical consolidated financial statements. The following selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, each of which is included elsewhere in this Annual Report.

Viper Energy Partners LP was formed in February 2014 and did not own any assets prior to June 17, 2014, the date Viper Energy Partners, LLC, the then-subsidiary of Diamondback, was contributed to Viper Energy Partners LP. We refer to Viper Energy Partners, LLC as “Viper Energy Partners LP Predecessor.” Viper Energy Partners LP Predecessor acquired its assets on September 19, 2013.

The contribution of Viper Energy Partners LP Predecessor to Viper Energy Partners LP was accounted for as a combination of entities under common control. Therefore, the following table presents the historical financial data of Viper Energy Partners LP as if Viper Energy Partners LP Predecessor and Viper Energy Partners LP were combined since inception.

Presented below is our historical financial data for the periods and as of the dates indicated. The historical financial data for the years ended December 31, 2018, 2017 and 2016 and the balance sheet data as of December 31, 2018 and 2017 are derived from our audited consolidated financial statements included elsewhere in this Annual Report. The historical financial data for the years ended December 31, 2015 and 2014 and the balance sheet data as of December 31, 2016, 2015 and 2014 are derived from our previously filed audited financial statements, which are not included in this Annual Report on Form 10-K. 
 
Year Ended December 31,
(In thousands, except per share amounts)
2018
 
2017
 
2016
 
2015
 
2014
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Total operating income
$
288,820

 
$
172,033

 
$
79,146

 
$
74,859

 
$
77,767

Total costs and expenses
85,833

 
58,212

 
88,457

 
50,484

 
37,350

Income (loss) from operations
202,987

 
113,821

 
(9,311
)
 
24,375

 
40,417

Total other income (expense), net
(12,475
)
 
(2,343
)
 
(1,588
)
 
44

 
(10,783
)
Income (loss) before income taxes
190,512

 
111,478

 
(10,899
)
 
24,419

 
29,634

Benefit from income taxes
(72,365
)
 

 

 

 

Net income (loss)
262,877

 
111,478

 
(10,899
)
 
24,419

 
29,634

Net income attributable to non-controlling interest
118,919

 

 

 

 

Net income (loss) attributable to Viper Energy Partners LP
$
143,958

 
$
111,478

 
$
(10,899
)
 
$
24,419

 
$
29,634

 
 
 
 
 
 
 
 
 
 
Allocation of net income:
 
 
 
 
 
 
 
 
 
Net income attributable to the period January 1, 2014 through June 22, 2014
 
 
 
 
 
 
 
 
$
7,021

Net income attributable to the period June 23, 2014 through December 31, 2014
 
 
 
 
 
 
 
 
22,613

Total net income
 
 
 
 
 
 
 
 
$
29,634

 
 
 
 
 
 
 
 
 
 
Net income (loss) attributable to common limited partners per unit:
 
 
 
 
 
 
 
 
 
Basic
$
2.01

 
$
1.07

 
$
(0.13
)
 
$
0.31

 
$
0.29

Diluted
$
2.01

 
$
1.07

 
$
(0.13
)
 
$
0.31

 
$
0.29

 
 
 
 
 
 
 
 
 
 

41


 
Year Ended December 31,
(In thousands, except per share amounts)
2018
 
2017
 
2016
 
2015
 
2014
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Weighted average number of common limited partner units outstanding:
 
 
 
 
 
 
 
 
 
Basic
71,546

 
104,318

 
83,081

 
79,717

 
78,090

Diluted
71,626

 
104,383

 
83,081

 
79,727

 
78,102


 
December 31,
(In thousands)
2018
 
2017
 
2016
 
2015
 
2014
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
22,676

 
$
24,197

 
$
9,213

 
$
539

 
$
15,110

Total assets
1,654,064

 
1,013,037

 
670,549

 
529,731

 
537,402

Total liabilities
417,022

 
99,129

 
122,651

 
34,587

 
2,051

Total unitholders’ equity
542,102

 
913,908

 
547,898

 
495,144

 
535,351

Total equity
1,237,042

 
913,908

 
547,898

 
495,144

 
535,351


 
Year Ended December 31,
(In thousands)
2018
 
2017
 
2016
 
2015
 
2014
Other Financial Data:
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
244,493

 
$
139,219

 
$
68,627

 
$
63,832

 
$
51,813

Net cash used in investing activities
(614,253
)
 
(344,079
)
 
(205,721
)
 
(43,907
)
 
(96,815
)
Net cash provided by (used in) financing activities
368,239

 
219,844

 
145,768

 
(34,496
)
 
59,350


 
Year Ended December 31,
(In thousands)
2018
 
2017
 
2016
 
2015
 
2014
Adjusted EBITDA(1)
$
140,888

 
$
157,556

 
$
72,660

 
$
68,317

 
$
70,579

(1)
For more information, please read “—Non-GAAP Financial Measure” below.

Non-GAAP Financial Measure

Adjusted EBITDA

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. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA in evaluating cash flow that will be available to pay distributions to our common unitholders.

We define Adjusted EBITDA as net income (loss) plus interest expense, net, interest expense–related party (net of capitalized interest), non-cash unit-based compensation expense, depletion expense, impairment expense, loss on revaluation of investment and benefit from income taxes. Adjusted EBITDA is not a measure of net income (loss) as determined by GAAP. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. 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.

Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss), royalty income, cash flow from operating activities or any other measure of financial performance or liquidity presented as determined in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.


42


The following table presents a reconciliation of Adjusted EBITDA, to net income, our most directly comparable GAAP financial measure for the periods indicated:
 
 
Year Ended December 31,
 
2018
 
2017
 
2016
 
2015
 
2014
 
(in thousands)
Net income (loss)
$
262,877

 
$
111,478

 
$
(10,899
)
 
$
24,419

 
$
29,634

Interest expense, net
13,849

 
3,164

 
2,455

 
1,110

 
487

Interest expense–related party, net of capitalized interest

 

 

 

 
10,755

Non-cash unit-based compensation expense
2,763

 
2,395

 
3,815

 
3,929

 
2,102

Depletion
58,830

 
40,519

 
29,820

 
35,436

 
27,601

Impairment

 

 
47,469

 
3,423

 

Loss on revaluation of investment
550

 

 

 

 

Benefit from income taxes
(72,365
)
 

 

 

 

Consolidated Adjusted EBITDA
266,504

 
157,556

 
72,660

 
68,317

 
70,579

EBITDA attributable to non-controlling interest
(125,616
)
 

 

 

 

Adjusted EBITDA attributable to Viper Energy Partners LP
$
140,888

 
$
157,556

 
$
72,660

 
$
68,317

 
$
70,579


43


ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto presented in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See “Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We are a publicly traded Delaware limited partnership formed by Diamondback in February 2014 to, among other things, own, acquire and exploit oil and natural gas properties in North America. The Partnership is currently focused on oil and natural gas properties in the Permian Basin and Eagle Ford Shale. As of December 31, 2018, our general partner held a 100% general partner interest in us, and Diamondback owned 731,500 common units and all of our 72,418,500 outstanding Class B units, representing approximately 59% of our total units outstanding. Diamondback also owns and controls our general partner.

We operate in one reportable segment engaged in the acquisition of oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties principally located in the Permian Basin of West Texas.

Recapitalization, Tax Status Election and Related Transactions
On May 9, 2018, we filed an election with the Internal Revenue Service to change our federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on that date we (i) amended and restated our First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, or Operating Company, (iii) amended and restated our existing registration rights agreement with Diamondback and (iv) entered into an exchange agreement with Diamondback, our general partner and the Operating Company. Simultaneously with the effectiveness of these agreements, Diamondback delivered and assigned to us the 73,150,000 common units Diamondback owned in exchange for (i) 73,150,000 of our newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018, or Recapitalization Agreement. Immediately following that exchange, we continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and Diamondback owned the remaining approximately 64% of the outstanding units issued by the Operating Company. The Operating Company units and our Class B units owned by Diamondback are exchangeable from time to time for the Partnership’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit).

On May 10, 2018, the change in our income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1.0 million to us in respect of its general partner interest and (ii) Diamondback made a cash capital contribution of $1.0 million to us in respect of the Class B units. Diamondback, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, Diamondback also exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 of our common units and a cash amount of $10,000 representing a proportionate return of the $1.0 million invested capital in respect of our Class B units. The General Partner continues to serve as our general partner and Diamondback continues to control us. After the effectiveness of the tax status election and the completion of related transactions, our minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure was adopted to provide anticipated significant benefits to our business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to our Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and our Current Report on Form 8-K filed with the SEC on May 15, 2018.

Sources of Our Income

Our income is primarily derived from royalty payments we receive from our operators based on the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from natural gas during processing. Royalty payments may vary significantly from period to period as a result of changes in commodity prices, production mix and volumes of production sold by our operators.


44


The following table presents the breakdown of our operating income for the following periods:
 
Year Ended December 31,
 
2018
 
2017
 
2016
Operating income
 
 
 
 
 
Royalty income
 
 
 
 
 
Oil sales
85
%
 
81
%
 
90
%
Natural gas sales
4
%
 
5
%
 
4
%
Natural gas liquid sales
8
%
 
6
%
 
6
%
Lease bonus income
3
%
 
8
%
 
%
 
100
%
 
100
%
 
100
%

As a result, our income is more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas liquids or natural gas prices. Our income may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas liquids and natural gas prices have historically been volatile.

During 2018, West Texas Intermediate posted prices ranged from $44.48 to $77.41 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.49 to $6.24 per MMBtu. On December 28, 2018, the West Texas Intermediate posted price for crude oil was $45.15 per Bbl and the Henry Hub spot market price of natural gas was $3.25 per MMBtu. Lower prices may not only decrease our income, but also potentially the amount of oil and natural gas that our operators can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our credit agreement, which may be redetermined at the discretion of our lenders.

2018 Transactions and Recent Developments

Our Equity Offerings

In July 2018, we completed an underwritten public offering of 10,080,000 common units, which included 1,080,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, Diamondback owned approximately 59% of our total units then outstanding. We received net proceeds from this offering of approximately $303.1 million, after deducting underwriting discounts and commissions and estimated offering expenses. We used the net proceeds to purchase units of the Operating Company. The Operating Company in turn used the net proceeds to repay a portion of the $361.5 million then outstanding borrowings under the revolving credit facility.

Recent Acquisitions

During 2018, we acquired mineral interests from unrelated third parties underlying 3,585 net royalty acres for an aggregate purchase price of approximately $440.4 million and, as of December 31, 2018, had mineral interests underlying 14,841 net royalty acres. We funded these acquisitions primarily with cash on hand and borrowings under its revolving credit facility

On August 15, 2018, we acquired mineral interests from Diamondback underlying 32,424 gross (1,696 net royalty) acres primarily in Pecos County, Texas, in the Permian Basin, approximately 80% of which are operated by Diamondback, for $175.0 million.

Production and Operational Update

Our average daily production during the year ended December 31, 2018 was 17,275 BOE/d (70% oil), and our operators received an average of $56.13 per Bbl of oil, $24.41 per Bbl of natural gas liquids and $2.22 per Mcf of natural gas, for an average realized price of $44.83 per BOE.

During the fourth quarter of 2018, the operators of our Spanish Trail mineral interests brought online eight gross horizontal wells with an average royalty interest of 21%, consisting of two Lower Spraberry and six Wolfcamp wells. The operators of our Pecos County mineral interests brought online 11 gross horizontal wells with an average royalty interest of 2.7%, consisting of nine Wolfcamp A, one Second Bone Spring and one Third Bone Spring wells. Additionally, there is active development activity on our mineral acreage outside of Spanish Trail in Loving, Reeves, Midland, Pecos, Ward, Martin, Howard and Glasscock counties. As of January 23, 2019, there were 40 active rigs on our acreage and 619 active drilling permits filed in the past six months.


45


We declared a cash dividend for the fourth quarter of 2018 of $0.51 per common unit, payable on February 25, 2019, to unitholders of record at the close of business on February 19, 2019.

Principal Components of Our Cost Structure

Production and Ad Valorem Taxes

Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties.

General and Administrative

In connection with the closing of the IPO, our general partner and Diamondback entered into the first amended and restated agreement of limited partnership, dated as of June 23, 2014. The partnership agreement requires us to reimburse our general partner for all direct and indirect expenses incurred or paid on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. The partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine the expenses that are allocable to us.

Depreciation, Depletion and Amortization

Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization.

Income Tax Expense

Prior to our change in federal income tax status, we were organized as a pass-through entity for income tax purposes. As a result, our partners were responsible for federal income taxes on their share of our taxable income. Subsequent to our change in federal income tax status, we are subject to federal income taxes at the corporate statutory rate of 21%.

We are subject to the Texas margin tax. For the year ended December 31, 2018, we accrued $0.2 million for Texas margin tax payable pursuant to our tax sharing agreement with Diamondback. For the years ended December 31, 2017 and 2016, we did not accrue any Texas margin tax.


46


Results of Operations
    
The following table summarizes our revenue and expenses and production data for the periods indicated:
 
Year Ended December 31,
 
2018
 
2017
 
2016
 
(In thousands)
Operating Results:
 
 
 
 
 
Operating income:
 
 
 
 
 
Royalty income
$
282,661

 
$
160,163

 
$
78,837

Lease bonus income
2,920

 
11,764

 

Lease bonus income - related party
3,109

 
106

 
309

Other operating income
130

 

 

Total operating income
288,820

 
172,033

 
79,146

Costs and expenses:
 
 
 
 
 
Production and ad valorem taxes
19,048

 
10,608

 
5,544

Gathering and transportation

 
789

 
415

Depletion
58,830

 
40,519

 
29,820

Impairment

 

 
47,469

General and administrative expenses
7,955

 
6,296

 
5,209

Total costs and expenses
85,833

 
58,212

 
88,457

Income (loss) from operations
202,987

 
113,821

 
(9,311
)
Other income (expense):
 
 
 
 
 
Interest expense, net
(13,849
)
 
(3,164
)
 
(2,455
)
Loss on revaluation of investment
(550
)
 

 

Other income, net
1,924

 
821

 
867

Total other income (expense), net
(12,475
)
 
(2,343
)
 
(1,588
)
Income (loss) before income taxes
190,512

 
111,478

 
(10,899
)
Benefit from income taxes
(72,365
)
 

 

Net income (loss)
262,877

 
111,478

 
(10,899
)
Net income attributable to non-controlling interest
118,919

 

 

Net income (loss) attributable to Viper Energy Partners LP
$
143,958

 
$
111,478

 
$
(10,899
)


47


 
Year Ended December 31,
 
2018
 
2017
 
2016
 
(In thousands)
Production Data:
 
 
 
 
 
Oil (MBbls)
4,399

 
2,899

 
1,778

Natural gas (MMcf)
5,840

 
3,549

 
1,490

Natural gas liquids (MBbls)
933

 
533

 
328

Combined volumes (MBOE)
6,305

 
4,024

 
2,354

Daily combined volumes (BOE/d)
17,275

 
11,023

 
6,432

% Oil
70
%
 
72
%
 
76
%
 
 
 
 
 
 
Average sales prices:
 
 
 
 
 
Oil, realized ($/Bbl)
$
56.13

 
$
48.36

 
$
40.23

Natural gas realized ($/Mcf)
2.22

 
2.62

 
2.08

Natural gas liquids ($/Bbl)
24.41

 
20.02

 
12.84

Average price realized ($/BOE)
44.83

 
39.81

 
33.49

 
 
 
 
 
 
Average Costs ($/BOE):
 
 
 
 
 
Production and ad valorem taxes
$
3.02

 
$
2.64

 
$
2.35

Gathering and transportation expense

 
0.20

 
0.18

General and administrative - cash component
0.82

 
0.97

 
0.59

Total operating expense - cash
$
3.84

 
$
3.81

 
$
3.12

 
 
 
 
 
 
General and administrative - non-cash component
$
0.44

 
$
0.59

 
$
1.62

Interest expense, net
2.20

 
0.79

 
1.04

Depletion
9.33

 
10.07

 
12.67


Comparison of the Years Ended December 31, 2018, 2017 and 2016

Royalty Income

Our royalty income for the years ended December 31, 2018, 2017 and 2016 was $282.7 million, $160.2 million and $78.8 million, respectively. Our royalty income is a function of oil, natural gas liquids and natural gas production volumes sold and average prices received for those volumes.

In addition to the increase in average prices received during the year ended December 31, 2018 as compared to the year ended December 31, 2017, we also benefited from a 57% increase in combined volumes sold by our operators. During the year ended year ended December 31, 2017, average prices received and combined volumes sold by our operators also increased as compared to the year ended December 31, 2016.
 
2018 vs. 2017
 
2017 vs. 2016
 
Change in prices
Production volumes(1)
Total net dollar effect of change
 
Change in prices
Production volumes(1)
Total net dollar effect of change
 
(dollars in thousands except change in prices)
Effect of changes in price:
 
 
 
 
 
 
 
Oil
$
7.77

4,399

$
34,177

 
$
8.13

2,899

$
23,572

Natural gas
(0.40
)
5,840

(2,336
)
 
0.54

3,549

1,916

Natural gas liquids
4.39

933

4,094

 
7.18

533

3,829

Total income due to change in price
 
 
$
35,935

 
 
 
$
29,317



48


 
2018 vs. 2017
 
2017 vs. 2016
 
Change in production volumes(1)
Prior period average prices
Total net dollar effect of change
 
Change in production volumes(1)
Prior period average prices
Total net dollar effect of change
 
(dollars in thousands except average prices)
Effect of changes in production volumes:
 
 
 
 
 
 
 
Oil
1,501

$
48.36

$
72,568

 
1,121

$
40.23

$
45,090

Natural gas
2,291

2.62

6,002

 
2,059

2.08

4,282

Natural gas liquids
399

20.02

7,993

 
205

12.84

2,637

Total income due to change in production volumes
 
 
86,563

 
 
 
52,009

Total change in income
 
 
$
122,498

 
 
 
$
81,326

(1)
Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

Lease Bonus Income

Lease bonus income decreased by $5.8 million from $11.9 million for the year ended December 31, 2017 to $6.0 million for the year ended December 31, 2018. During the year ended December 31, 2018, we received $3.4 million which was attributable to lease bonus payments to extend the term of 15 leases, reflecting an average bonus of $4,513 per acre, and $2.7 million attributable to lease bonus payments on six new leases, reflecting an average bonus of $12,740 per acre. During the year ended December 31, 2017, we received $2.8 million which was attributable to lease bonus payments to extend the term of seven leases, reflecting an average bonus of $3,442 per acre, and $9.1 million attributable to lease bonus payments on three new leases, reflecting an average bonus of $14,320 per acre. During the year ended December 31, 2016, we received $0.3 million in lease bonus payments to extend the term of six leases, reflecting an average bonus of $1,371 per acre.

Other Operating Income

Other operating income was $0.1 million for the year ended December 31, 2018 primarily related to surface damage payments. We did not receive any other operating income for the year ended December 31, 2017 or 2016.

Impairment of Oil and Gas Properties

During the year ended December 31, 2016, we recorded an impairment of oil and natural gas properties of $47.5 million, as a result of the significant decline in commodity prices. No impairments were recorded for the year ended December 31, 2018 or 2017.

General and Administrative Expenses

For the years ended December 31, 2018, 2017 and 2016, we incurred general and administrative expenses of $8.0 million, $6.3 million and $5.2 million, respectively. The increase of $1.7 million in general and administrative expenses for the year ended December 31, 2018 as compared to 2017 was primarily due to expenses related to the change in tax status. The increase of $1.1 million for the year ended December 31, 2017 as compared to 2016 was primarily due to reimbursements paid to the general partner. The general and administrative expenses primarily reflect costs associated with us being a publicly traded limited partnership, unit-based compensation and the amounts reimbursed to our general partner under our partnership agreement. For each of the years ended December 31, 2018 and 2017, the General Partner received reimbursements from us of $2.5 million. For the year ended December 31, 2016, the General Partner did not receive any reimbursements from us.

Net Interest Expense

Net interest expense for the years ended December 31, 2018, 2017 and 2016 was $13.8 million, $3.2 million and $2.5 million, respectively. The increase of $10.7 million in net interest expense for the year ended December 31, 2018 as compared to 2017 was due to a higher average interest rate and increased average level of outstanding borrowings. The increase of $0.7 million in net interest expense for the year ended December 31, 2017 as compared to 2016 was also primarily due to a higher average interest rate and increased average level of outstanding borrowings under our credit agreement.


49


Provision for (Benefit From) Income Taxes

We recorded an income tax benefit of $72.4 million for the year ended December 31, 2018. Prior to the second quarter of 2018, we had no provision for or benefit from income taxes. Total income tax benefit for the year ended December 31, 2018 differed from amounts computed by applying the federal statutory tax rate to pre-tax income for the period primarily due to deferred taxes recognized as a result of our change in federal income tax status.

Adjusted EBITDA
    
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. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA in evaluating cash flow that will be available to pay distributions to our common unitholders.

We define Adjusted EBITDA as net income (loss) plus interest expense, net, non-cash unit-based compensation expense, depletion expense, impairment expense, loss on revaluation of investment and benefit from income taxes. Adjusted EBITDA is not a measure of net income (loss) as determined by GAAP. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. 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.

Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss), royalty income, cash flow from operating activities or any other measure of financial performance or liquidity presented as determined in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDA, to net income, our most directly comparable GAAP financial measure for the periods indicated:
 
Year Ended December 31,
 
2018
 
2017
 
2016
 
(in thousands)
Net income (loss)
$
262,877

 
$
111,478

 
$
(10,899
)
Interest expense, net
13,849

 
3,164

 
2,455

Non-cash unit-based compensation expense
2,763

 
2,395

 
3,815

Depletion
58,830

 
40,519

 
29,820

Impairment

 

 
47,469

Loss on revaluation of investment
550

 

 

Benefit from income taxes
(72,365
)
 

 

Consolidated Adjusted EBITDA
266,504

 
157,556

 
72,660

EBITDA attributable to non-controlling interest
(125,616
)
 

 

Adjusted EBITDA attributable to Viper Energy Partners LP
$
140,888

 
$
157,556

 
$
72,660


Liquidity and Capital Resources

Overview

Our primary sources of liquidity have been cash flows from operations, proceeds from equity offerings and borrowings under our credit agreement, and our primary uses of cash have been, and are expected to continue to be, distributions to our unitholders and replacement and growth capital expenditures, including the acquisition of oil and natural gas interests. We intend to finance potential future acquisitions through a combination of cash on hand, borrowings under our credit agreement and, subject to market conditions and other factors, proceeds from one or more capital market transactions, which may include debt or equity offerings. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including commodity prices and general economic, financial, competitive, legislative, regulatory and other factors, including weather.

50



The board of directors of our general partner has adopted a policy pursuant to which the Operating Company will distribute all of the available cash it generates each quarter to unitholders (including us), and we, in turn, will distribute all of the available cash we receive from the Operating Company to our common unitholders.

Cash distributions are made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for us and the Operating Company for each quarter is determined by the board of directors of our general partner following the end of such quarter. Available cash for the Operating Company for each quarter will generally equal its Adjusted EBITDA reduced for 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 our general partner deems necessary or appropriate, if any, and our available cash will generally equal our Adjusted EBITDA (which will be our proportionate share of the available cash distributed to us by the Operating Company), less as a result of the Tax Election, cash needed for the payment of income taxes payable by us, if any.

We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The board of directors of our general partner may change our distribution policy at any time. Our partnership agreement does not require us to pay distributions to our common unitholders on a quarterly or other basis.

The following table presents cash distributions approved by the board of directors of our general partner for the periods presented:
Declaration Date
 
Quarter
 
Amount per Common Unit
 
Payment Date
 
Amount Distributed to Diamondback